UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



(mark one)
x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, ~~2016~~2017

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 1-10499

NORTHWESTERN CORPORATION

(Exact name of registrant as specified in its charter)



Delaware		46-0172280
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
3010 W. 69^th Street, Sioux Falls, South Dakota		57108
(Address of principal executive offices)		(Zip Code)
Registrant’s telephone number, including area code: 605-978-2900

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non- accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” ~~and~~, “smaller reporting company”, and "emerging growth company" in Rule 12b-2 of the Exchange Act.



Large Accelerated Filer x	Accelerated Filer o	Non-accelerated Filer o	Smaller Reporting Company o	Emerging Growth Company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. Yes o No o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Common Stock, Par Value $0.01

~~48,311,224~~48,471,447 shares outstanding at July ~~15, 2016~~21, 2017

NORTHWESTERN CORPORATION

FORM 10-Q

INDEX



		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION		4
Item 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Statements of Income — Three and Six Months Ended June 30, ~~2016~~2017 and ~~2015~~2016	4
	Condensed Consolidated Statements of Comprehensive Income — Three and Six Months Ended June 30, ~~2016~~2017 and ~~2015~~2016	5
	Condensed Consolidated Balance Sheets — June 30, ~~2016~~2017 and December 31, ~~2015~~2016	6
	Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, ~~2016~~2017 and ~~2015~~2016	7
	Condensed Consolidated Statements of Shareholders' Equity — Six Months Ended June 30, ~~2016~~2017 and ~~2015~~2016	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3130
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5553
Item 4.	Controls and Procedures	5654
PART II. OTHER INFORMATION		5755
Item 1.	Legal Proceedings	5755
Item 1A.	Risk Factors	5755
Item 6.	Exhibits	6461
SIGNATURES		6562

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

On one or more occasions, we may make statements in this Quarterly Report on Form 10-Q regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference in this Quarterly Report, relating to management's current expectations of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

Words or phrases such as “anticipates," “may," “will," “should," “believes," “estimates," “expects," “intends," “plans," “predicts," “projects," “targets," “will likely result," “will continue" or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that we will achieve our projections. Factors that may cause such differences include, but are not limited to:

adverse determinations by regulators, as well as potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, could have a material effect on our liquidity, results of operations and financial condition;

changes in availability of trade credit, creditworthiness of counterparties, usage, commodity prices, fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, may reduce revenues or may increase operating costs, each of which could adversely affect our liquidity and results of operations;

unscheduled generation outages or forced reductions in output, maintenance or repairs, which may reduce revenues and increase cost of sales or may require additional capital expenditures or other increased operating costs; and

adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories.

We have attempted to identify, in context, certain of the factors that we believe may cause actual future experience and results to differ materially from our current expectation regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the uncertainties described under the caption “Risk Factors” which is part of the disclosure included in Part II, Item 1A of this Quarterly Report on Form 10-Q.

From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-K, 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. We believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable. However, any or all of the forward-looking statements in this Quarterly Report on Form 10-Q, our reports on Forms 10-K and 8-K, our other reports on Form 10-Q, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions, which turn out to be inaccurate, or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Quarterly Report on Form 10-Q, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of any of our forward-looking statements in this Quarterly Report on Form 10-Q or other public communications as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. However, your attention is directed to any further disclosures made on related subjects in our subsequent reports filed with the Securities and Exchange Commission (SEC) on Forms 10-K, 10-Q and 8-K and Proxy Statements on Schedule 14A.

Unless the context requires otherwise, references to “we,” “us,” “our,” “NorthWestern Corporation,” “NorthWestern Energy,” and “NorthWestern” refer specifically to NorthWestern Corporation and its subsidiaries.



PART 1. FINANCIAL INFORMATION


ITEM 1.	FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015			2017			2016			2017			2016
Revenues
Electric	$	248,403		$	221,362		$	489,745		$	457,408		$	233,866		$	248,403		$	500,105		$	489,745
Gas	44,717			49,198			135,914			159,163			49,993			44,717			151,066			135,914
Total Revenues	293,120			270,560			625,659			616,571			283,859			293,120			651,171			625,659
Operating Expenses
Cost of sales	81,693			79,527			197,127			191,918			84,000			81,693			203,817			197,127
Operating, general and administrative	72,579			61,720			152,440			142,843			75,188			72,579			156,150			152,440
Property and other taxes	35,208			32,454			70,629			65,241			39,481			35,208			79,409			70,629
Depreciation and depletion	39,898			35,727			79,788			71,546			41,495			39,898			82,956			79,788
Total Operating Expenses	229,378			209,428			499,984			471,548			240,164			229,378			522,332			499,984
Operating Income	63,742			61,132			125,675			145,023			43,695			63,742			128,839			125,675
Interest Expense, net	(26,421		)	(22,943		)	(50,930		)	(46,058		)	(23,408		)	(26,421		)	(46,808		)	(50,930		)
Other Income	1,195			995			4,297			1,660			2,123			1,195			3,623			4,297
Income Before Income Taxes	38,516			39,184			79,042			100,625			22,410			38,516			85,654			79,042
Income Tax Expense	(2,947		)	(8,211		)	(5,419		)	(18,227		)	(580		)	(2,947		)	(7,257		)	(3,606		)
Net Income	$	35,569		$	30,973		$	73,623		$	82,398		$	21,830		$	35,569		$	78,397		$	75,436

Average Common Shares Outstanding	48,309			47,044			48,275			47,011			48,451			48,309			48,418			48,275
Basic Earnings per Average Common Share	$	0.74		$	0.66		$	1.53		$	1.75		$	0.45		$	0.74		$	1.62		$	1.57
Diluted Earnings per Average Common Share	$	0.73		$	0.65		$	1.52		$	1.74		$	0.44		$	0.73		$	1.61		$	1.55
Dividends Declared per Common Share	$	0.50		$	0.48		$	1.00		$	0.96		$	0.525		$	0.50		$	1.05		$	1.00

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(in thousands)


	Three Months Ended June 30,					Six Months Ended June 30,						Three Months Ended June 30,					Six Months Ended June 30,
	2016		2015			2016			2015			2017			2016		2017			2016
Net Income	$	35,569	$	30,973		$	73,623		$	82,398		$	21,830		$	35,569	$	78,397		75,436
Other comprehensive income (loss), net of tax:
Foreign currency translation	8		(56		)	(110		)	212			(104		)	8		(53		)	(110		)
Cash flow hedges:
Reclassification of net losses (gains) on derivative instruments	37		(91		)	74			(180		)
Total Other Comprehensive Income (Loss)	45		(147		)	(36		)	32
Reclassification of net losses on derivative instruments												93			37		186			74
Total Other Comprehensive (Loss) Income												(11		)	45		133			(36		)
Comprehensive Income	$	35,614	$	30,826		$	73,587		$	82,430		$	21,819		$	35,614	$	78,530		$	75,400

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)


	June 30, 2016			December 31, 2015			June 30, 2017			December 31, 2016
ASSETS
Current Assets:
Cash and cash equivalents	$	8,969		$	11,980		$	16,859		$	5,079
Restricted cash	6,588			6,634			5,608			4,426
Accounts receivable, net	115,833			154,410			123,925			159,556
Inventories	49,923			53,458			50,599			49,206
Regulatory assets	40,483			51,348			35,898			50,041
Other	16,195			8,830			15,128			11,887
Total current assets	237,991			286,660			248,017			280,195
Property, plant, and equipment, net	4,109,730			4,059,499			4,261,983			4,214,892
Goodwill	357,586			357,586			357,586			357,586
Regulatory assets	556,910			517,223			641,720			602,943
Other noncurrent assets	45,389			43,727			47,626			43,705
Total Assets	$	5,307,606		$	5,264,695		$	5,556,932		$	5,499,321
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,905		$	1,837		2,053			$	1,979
Short-term borrowings	256,806			229,874			303,658			300,811
Accounts payable	55,470			74,511			55,530			79,311
Accrued expenses	181,119			183,988			200,517			205,370
Regulatory liabilities	25,376			80,990			16,670			26,361
Total current liabilities	520,676			571,200			578,428			613,832
Long-term capital leases	25,373			26,325			23,320			24,346
Long-term debt	1,773,714			1,768,183			1,793,797			1,793,338
Deferred income taxes	553,824			501,532			615,510			575,582
Noncurrent regulatory liabilities	388,012			378,711			406,305			396,225
Other noncurrent liabilities	418,372			418,570			430,975			419,771
Total Liabilities	3,679,971			3,664,521			3,848,335			3,823,094
Commitments and Contingencies (Note 13)
Commitments and Contingencies (Note 12)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 51,956,014 and 48,311,079 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	520			518
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 52,091,239 and 48,470,756 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued							521			520
Treasury stock at cost	(96,265		)	(93,948		)	(96,689		)	(95,769		)
Paid-in capital	1,380,345			1,376,291			1,389,426			1,384,271
Retained earnings	351,667			325,909			424,920			396,919
Accumulated other comprehensive loss	(8,632		)	(8,596		)	(9,581		)	(9,714		)
Total Shareholders' Equity	1,627,635			1,600,174			1,708,597			1,676,227
Total Liabilities and Shareholders' Equity	$	5,307,606		$	5,264,695		$	5,556,932		$	5,499,321

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)


	Six Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2017			2016
OPERATING ACTIVITIES:
Net income	$	73,623		$	82,398		$	78,397		$	75,436
Items not affecting cash:
Depreciation and depletion	79,788			71,546			82,956			79,788
Amortization of debt issue costs, discount and deferred hedge gain	1,987			562			2,392			1,987
Stock-based compensation costs	3,361			2,331			3,826			3,361
Equity portion of allowance for funds used during construction	(1,608		)	(3,971		)	(2,298		)	(1,608		)
Loss (gain) on disposition of assets	1,054			(87		)
(Gain) loss on disposition of assets							(401		)	1,054
Deferred income taxes	5,535			19,919			6,320			3,722
Changes in current assets and liabilities:
Restricted cash	46			(12		)	(1,182		)	46
Accounts receivable	38,577			40,591			35,631			38,577
Inventories	3,535			4,032			(1,393		)	3,535
Other current assets	(7,365		)	(1,040		)	(3,241		)	(7,365		)
Accounts payable	(17,595		)	(30,186		)	(19,788		)	(17,595		)
Accrued expenses	786			(30,881		)	(4,853		)	786
Regulatory assets	10,865			20,579			14,143			10,865
Regulatory liabilities	(55,614		)	4,389			(9,691		)	(55,614		)
Other noncurrent assets	(3,099		)	(1,014		)	(6,781		)	(3,099		)
Other noncurrent liabilities	7,118			11,182			3,767			7,118
Cash Provided by Operating Activities	140,994			190,338			177,804			140,994
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(121,246		)	(131,170		)	(119,123		)	(121,246		)
Acquisitions	—			(492		)
Proceeds from sale of assets	137			80			379			137
Change in restricted cash	—			9,153
Cash Used in Investing Activities	(121,109		)	(122,429		)	(118,744		)	(121,109		)
FINANCING ACTIVITIES:
Treasury stock activity	(1,614		)	(1,008		)	411			(1,614		)
Dividends on common stock	(47,865		)	(44,760		)	(50,396		)	(47,865		)
Issuance of long-term debt	60,000			200,000			—			60,000
Repayments on long-term debt	(55,000		)	(150,016		)	—			(55,000		)
Issuances (repayments) of short-term borrowings, net	26,932			(47,931		)
Issuances of short-term borrowings, net							2,847			26,932
Financing costs	(5,349		)	(11,688		)	(142		)	(5,349		)
Cash Used in Financing Activities	(22,896		)	(55,403		)	(47,280		)	(22,896		)
(Decrease) Increase in Cash and Cash Equivalents	(3,011		)	12,506
Increase (Decrease) in Cash and Cash Equivalents							11,780			(3,011		)
Cash and Cash Equivalents, beginning of period	11,980			20,362			5,079			11,980
Cash and Cash Equivalents, end of period	$	8,969		$	32,868		$	16,859		$	8,969
Supplemental Cash Flow Information:
Cash (received) paid during the period for:
Cash paid (received) during the period for:
Income taxes	$	(2,922	)	$	27		$	61		$	(2,922	)
Interest	42,861			44,611			40,280			42,861
Significant non-cash transactions:
Capital expenditures included in trade accounts payable	11,054			9,199
Capital expenditures included in accounts payable							9,776			11,054

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF ~~COMMON~~ SHAREHOLDERS' EQUITY

(Unaudited)

(in thousands, except per share data)


	Number of Common Shares	Number of Treasury Shares	Common Stock		Paid in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders' Equity
Balance at December 31, 2014	50,522	3,607	$	505	$	1,313,844		$	(92,558	)	$	264,758		$	(8,766	)	$	1,477,783

Net income	—	—	—		—			—			82,398			—			82,398
Foreign currency translation adjustment	—	—	—		—			—			—			212			212
Reclassification of net gains on derivative instruments from Other Comprehensive Income (OCI) to net income, net of tax	—	—	—		—			—			—			(180		)	(180		)
Stock-based compensation	164	17	—		2,888			(1,567		)	—			—			1,321
Issuance of shares	—	—	2		(122		)	—			—			—			(120		)
Dividends on common stock ($0.96 per share)	—	—	—		—			—			(44,760		)	—			(44,760		)
Balance at June 30, 2015	50,686	3,624	$	507	$	1,316,610		$	(94,125	)	$	302,396		$	(8,734	)	$	1,516,654
																				Number of Common Shares	Number of Treasury Shares		Common Stock		Paid in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders' Equity
Balance at December 31, 2015	51,789	3,617	$	518	$	1,376,291		$	(93,948	)	$	325,909		$	(8,596	)	$	1,600,174		51,789	3,617		$	518	$	1,376,291		$	(93,948	)	$	325,909		$	(8,596	)	$	1,600,174

Net income	—	—	—		—			—			73,623			—			73,623			—	—		—		—			—			75,436			—			75,436
Accounting standard adoption																				—	—		—		—			—			2,603			—			2,603
Foreign currency translation adjustment	—	—	—		—			—			—			(110		)	(110		)	—	—		—		—			—			—			(110		)	(110		)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	—	—	—		—			—			—			74			74			—	—		—		—			—			—			74			74
Stock-based compensation	167	28	—		4,065			(2,317		)	—			—			1,748			167	28		—		4,065			(2,317		)	—			—			1,748
Issuance of shares	—	—	2		(11		)	—			—			—			(9		)	—	—		2		(11		)	—			—			—			(9		)
Dividends on common stock ($1.00 per share)	—	—	—		—			—			(47,865		)	—			(47,865		)	—	—		—		—			—			(47,865		)	—			(47,865		)
Balance at June 30, 2016	51,956	3,645	$	520	$	1,380,345		$	(96,265	)	$	351,667		$	(8,632	)	$	1,627,635		51,956	3,645		$	520	$	1,380,345		$	(96,265	)	$	356,083		$	(8,632	)	$	1,632,051

Balance at December 31, 2016																				51,958	3,626		$	520	$	1,384,271		$	(95,769	)	$	396,919		$	(9,714	)	$	1,676,227

Net income																				—	—		—		—			—			78,397			—			78,397
Foreign currency translation adjustment																				—	—		—		—			—			—			(53		)	(53		)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax																				—	—		—		—			—			—			186			186
Stock-based compensation																				133	(6	)	1		5,155			(920		)	—			—			4,236
Dividends on common stock ($1.05 per share)																				—	—		—		—			—			(50,396		)	—			(50,396		)
Balance at June 30, 2017																				52,091	3,620		$	521	$	1,389,426		$	(96,689	)	$	424,920		$	(9,581	)	$	1,708,597

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Reference is made to Notes to Financial Statements included in NorthWestern Corporation’s Annual Report)

(Unaudited)


(1)	Nature of Operations and Basis of Consolidation

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately ~~701,000~~709,600 customers in Montana, South Dakota and Nebraska.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The unaudited Condensed Consolidated Financial Statements (Financial Statements) reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to June 30, ~~2016~~2017, have been evaluated as to their potential impact to the Financial Statements through the date of issuance.

The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the ~~SEC.~~Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends that these unaudited Financial Statements be read in conjunction with the audited financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016.

Variable Interest Entities

A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance.

Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain ~~Qualifying Facility~~qualifying co-generation facilities and qualifying small power production facilities (QF) ~~plants.~~. We identified one QF contract that may constitute a VIE. We entered into a 40-year power purchase contract in 1984 with this 35 Megawatt (MW) coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per Megawatt Hour (MWH) (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $~~259.5~~233.1 million through 2024.

(2) New Accounting Standards

Accounting Standards Adopted

Stock Compensation - During the fourth quarter of 2016, we early adopted the provisions of Accounting Standards Update No. 2016-09 (ASU 2016-09), Improvements to Employee Share-Based Payment Accounting, revising certain elements of the accounting for share-based payments. As a result of this adoption, during the fourth quarter of 2016, excess tax benefits of $1.8 million related to vested share-based compensation awards were recorded as a decrease in income tax expense and a $0.04 increase in our earnings per share in the Condensed Consolidated Statement of Income. In addition, we recorded a cumulative-effect adjustment to retained earnings as of the date of adoption of $2.6 million in the Condensed Consolidated Balance Sheets. The guidance also requires that in future filings that include the previously issued interim financial

information, the interim financial information is presented on a recast basis to reflect the adoption of ASU 2016-09 as of January 1, 2016. The Condensed Consolidated Financial Statements for the six months ended June 30, 2016, have been recast to reflect this adoption, resulting in an increase in net income and earnings per share.

Accounting Standards Issued

Revenue Recognition - In May 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance on the recognition of revenue from contracts with customers, which will supersede nearly all existing revenue recognition guidance under GAAP. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. ~~The FASB delayed~~

We expect to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the ~~effective date~~modified retrospective method of ~~this guidance~~adoption. This method requires a cumulative-effect adjustment to be recorded on the ~~first quarter of 2018, with early adoption permitted~~balance sheet as of the ~~original effective date~~beginning of 2018, if applicable, as if the standard had always been in effect. Disclosures in 2018 will include a reconciliation of results under the new revenue recognition guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods.

Our revenues are primarily from tariff based sales, which are in the scope of the ~~first quarter~~guidance. We provide gas and/or electricity to customers under these tariffs without a defined contractual term (‘at-will’). We expect that the revenue from these arrangements will be equivalent to the electricity or gas supplied and billed in that period (including estimated billings). As such, we do not expect that there will be a significant shift in the timing or pattern of ~~2017.~~revenue recognition for such sales. The evaluation of other revenue streams is ongoing, including those tied to longer term contractual commitments. In our evaluation, we are also monitoring unresolved implementation issues for our industry, including the impacts of the guidance on our ability to recognize revenue for certain contracts where collectability is uncertain. The final resolution of these issues and completion of our assessment could impact our current accounting policies and revenue recognition.

Retirement Benefits - In March 2017, the FASB issued new guidance on the presentation of net periodic costs related to benefit plans. The new guidance requires the service cost component of net periodic benefit cost to be included within operating income within the same line as other compensation expenses. All other components of net periodic costs must be outside of operating income. In addition, the updated guidance permits only the service cost component of net periodic costs to be capitalized to inventory or property, plant and equipment. This represents a change from current accounting and financial reporting, with presentation of the aggregate net periodic benefit costs on the income statement within operating income, and which permits all components of net periodic costs to be capitalized.

This guidance is effective for interim and annual periods beginning January 1, 2018. These amendments will be applied retrospectively for the presentation of the various components of net periodic costs and prospectively for the change in eligible costs to be capitalized. We ~~are currently evaluating~~have not yet fully determined the ~~impact~~impacts of adoption of ~~this new guidance on our Financial Statements and disclosures.~~the standard, but expect that as a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the current ratemaking treatment.

Leases - In February 2016, the FASB issued revised guidance on accounting for leases. The new standard requires a lessee to recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term for all leases with terms longer than 12 months. Leases with a term of 12 months or less will be accounted for similar to existing guidance for operating leases. Recognition, measurement and presentation of expenses will depend on classification as a finance or operating lease. The new guidance will be effective for us in our first quarter of 2019 and early adoption is permitted. A modified retrospective transition approach is required for lessees for ~~capital and operating~~ leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the impact of adoption of this ~~guidance, and~~guidance. We do not have a significant amount of capital or operating leases. Therefore, based on our initial analysis we do not expect itthis guidance to have a significant impact on our Financial Statements and ~~disclosures.~~disclosures other than an expected increase in assets and liabilities.

Statement of Cash Flows - In ~~March~~August 2016, the FASB issued guidance ~~revising certain elements~~that addresses eight classification issues related to the presentation of the accounting for share-based payments. The new standard is intended to simplify several aspects of the accounting for share-based payment award transactions including: (a) income tax consequences; (b) classification of awards as either equity or liabilities;cash receipts and ~~(c) classification on~~cash payments in the statement of cash flows. The new guidance will be effective for us in our first quarter of ~~2017,~~2018, with early adoption permitted. We are currently evaluating the impact of adoption of this guidance on our ~~Financial Statements and disclosures.~~Statement of Cash Flows.

~~Accounting Standards Adopted~~

In ~~February 2015,~~November 2016, the FASB issued ~~consolidation~~ guidance that ~~eliminated two consolidation models~~a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and ~~requires all legal~~

~~entities to~~amounts generally described as restricted cash or restricted cash equivalents. The new guidance will be ~~evaluated under a voting interest entity model or a variable interest entity model. Both models require the reporting entity to identify whether it has a controlling financial interest~~effective for us in ~~a legal entity and is therefore required to consolidate the entity. We adopted this guidance during the~~our first quarter of ~~2016~~2018, with ~~no material~~early adoption permitted. We are currently evaluating the impact toof adoption of this guidance on our ~~Financial Statements and disclosures.~~Statement of Cash Flows.

In April 2015, the FASB issued accounting guidance that changes the presentation of debt issuance costs. The core principle of this revised accounting guidance is that debt issuance costs are not assets, but adjustments to the carrying cost of debt. During the first quarter of 2016, we retrospectively adopted this guidance. The implementation of this accounting standard resulted in a reduction of other noncurrent assets and long-term debt of $13.9 million and $13.0 million in the Condensed Consolidated Balance Sheets as of December 31, 2015 and 2014, respectively.

(3) Regulatory Matters

Montana Natural Gas General Rate Filing

In June 2017, we reached a settlement agreement with intervenors in our natural gas rate case. This settlement included an overall increase in delivery services and production charges of approximately $5.7 million, based upon a 6.96 percent rate of return (9.55 percent return on equity, 4.67 percent cost of debt and 53.2 percent debt to rate base). In our initial filing in September 2016, we requested an annual increase to natural gas rates of approximately $10.9 million, with rebuttal testimony filed in April 2017 supporting a revised requested annual increase to rates of approximately $9.4 million. The natural gas production part of this filing includes a request for cost-recovery and permanent inclusion in base rates of fields acquired in August 2012 and December 2013 in northern Montana's Bear Paw Basin. Actual production costs are currently recovered in customer rates on an interim basis through our supply tracker.

The MPSC held a work session on July 20, 2017, and voted to draft an order accepting the settlement with modifications. We estimate that these modifications lower the increase in delivery services and production charges to approximately $5.1 million. Due to the MPSC's modification of the settlement, any of the parties may elect to withdraw and request a new hearing. We will evaluate the impact of these modifications upon receipt of a final order, which we expect in August 2017.

QF Decision

Under the Public Utility Regulatory Policies Act (PURPA), electric utilities are required, with exceptions, to purchase energy and capacity from independent power producers that are QFs. The MPSC held a work session in June 2017 to discuss our application for approval of a revised tariff for standard rates for small QFs. In July 2017, the MPSC issued an order establishing a maximum 10-year contract length with a rate adjustment after the first five years, and approving rates that do not include costs associated with the risk of future carbon dioxide emissions regulations. We expect this will result in substantially lower rates for these contracts. In this same order, the MPSC indicated they will apply the 10-year contract term to us for future electric supply resource transactions. We have significant generation capacity deficits and negative reserve margins. In addition to our responsibility to meet peak demand, national reliability standards effective July 2016 require us to have even greater dispatchable generation capacity available and be capable of increasing or decreasing output to address the irregular nature of intermittent generation such as wind or solar. Our 2016 resource plan identified price and reliability risks to our customers of solely relying upon market purchases to address these needs. We are evaluating the impact of this decision and have suspended our competitive solicitation process to determine the lowest-cost / least-risk approach for addressing our intermittent capacity and reserve margin needs in Montana.

Montana House Bill 193 / Electric and Natural Gas Tracker Filings

~~Each~~House Bill 193 - In April 2017, the Montana legislature passed House Bill 193 (HB 193), repealing the statute that provided for mandatory recovery of our prudently incurred electric supply costs effective July 1, 2017. In May 2017, the MPSC issued a Notice of Commission Action (NCA) initiating a process to develop a replacement electric tracker mechanism. We filed a motion for reconsideration of the May 2017 NCA. On July 7, 2017, the MPSC issued an additional NCA addressing the arguments in our motion for reconsideration and identifying three replacement mechanism alternatives for consideration. Two of the replacement mechanism alternatives identified include updating the fixed rate portion of the recovery of our electric supply assets in addition to the variable costs that were recovered through the prior electric tracker. This would be accomplished through an electric supply revenue requirements filing to be made by us by September 30, 2017. The July 2017 NCA also raises questions regarding our earnings as compared with our authorized rate of return for 2016 for electric supply. As noted below in the hydro compliance filing discussion, our 2016 MPSC annual report indicates we earned less than our authorized rate of return with electric delivery service and supply combined. The NCA established a timeline for the parties to provide comments in July 2017, on the issue of whether the MPSC should require a September 2017 filing, and we are awaiting a further decision.

On July 14, 2017, we filed a proposed electric Power Cost and Credit Adjustment Mechanism (PCCAM) with the MPSC. We believe the PCCAM filing is consistent with the MPSC's advocacy for HB 193, the MPSC's May and July 2017 NCAs, and the Montana-Dakota Utilities (MDU) Montana adjustment mechanism that allows for recovery of 90 percent of the increases or decreases in fuel and purchased energy costs from an established baseline. However, we cannot guarantee how the MPSC may

apply the statute in establishing a revised mechanism. We expect application of the new mechanism to variable costs to be retroactive to the effective date of HB 193.

Electric Tracker Open Dockets - 2015/2016 - 2016/2017 - Under the previous statutory tracker mechanism, each year we ~~submit~~submitted an electric ~~and natural gas~~ tracker filing for recovery of supply costs for the 12-month period ended June 30 and for the projected supply costs for the next 12-month ~~period.~~period, which were subject to a prudency review. In June 2017, the MPSC consolidated the dockets for the 2015/2016 and 2016/2017 tracker periods, which are approved on an interim basis. The ~~Montana Public Service Commission (MPSC) reviews such filings and makes its cost recovery determination based on whether or~~MPSC has not ~~our supply procurement activities were prudent.~~established a schedule regarding these remaining open dockets under the prior statutory tracker.

~~During the second quarter of 2016,~~Natural Gas Tracker - 2016/2017 - In May 2017, we filed our ~~2016~~ annual ~~electric and~~ natural gas tracker ~~filings~~filing for the ~~2015/2016~~2016/2017 tracker ~~period. We received orders from~~period, which the MPSC ~~in July 2016 approving the filings~~approved on an interim basis. HB 193 does not impact our natural gas recovery mechanism.

Electric ~~Trackers~~Tracker Litigation - 2012/2013 - 2013/2014 (Consolidated Docket) and 2014/2015 (2015 Tracker) - ~~The~~In 2016, we received final electric tracker orders from the MPSC ~~held~~in the Consolidated Docket and 2015 Tracker, resulting in a ~~work session~~$12.4 million disallowance of costs, including interest. In June 2016, we filed an appeal in ~~March 2016 and directed staff to draft a final order~~Montana District Court (Lewis & Clark County) of the MPSC decision in our 2015 Tracker docket to disallow certain portfolio modeling costs. Also, in September 2016, we appealed the MPSC’s decisions in the Consolidated Docket ~~that reflects a~~regarding the disallowance of ~~both~~ replacement power costs from a 2013 outage at Colstrip Unit 4 and ~~portfolio~~the modeling/planning costs, arguing that these decisions were arbitrary and capricious, and violated Montana law. We brought this action in Montana District Court, as well (Yellowstone County). In the Consolidated Docket appeal, we abandoned our appeal of the modeling costs (approximately $0.3 million) reserving the issue for our 2015 Tracker appeal. The briefing in ~~each of~~ the ~~periods. On~~Consolidated Docket appeal concluded in May 2017, and we expect a decision within the ~~same day, in~~next 12 months. We expect a ~~separate work session, the MPSC directed staff to draft a final order~~decision in the 2015 Tracker that approved a stipulation between us and the Montana Consumer Counsel, but disallowed portfolio modeling costs. Based on the March 2016 work sessions, we recorded a disallowance during the first quarter of 2016 totaling approximately $10.3 million, which included $8.2 million of replacement power costs and $2.1 million of modeling costs.

~~In April 2016, we received the final written order~~appeal in the 2015 Tracker, which was consistent with the work session. We filed a motion for reconsideration of the decision with the MPSC regarding the disallowance of portfolio modeling costs, which was denied. In June 2016, we filed an appeal of the decision in Montana District Court.

In May 2016, we received the final written order in the Consolidated Docket. The written order clarified the disallowance of modeling costs, resulting in a reduction of the disallowance recorded during the first quarter of 2016 of $0.8 million, which is reflected as a reduction in cost of sales in the Condensed Consolidated Statement of Income for the three months ended June 30, 2016.

~~In addition, the May 2016 Consolidated Docket final order upheld the March 2016 decision regarding replacement power costs, concluding that we were imprudent by failing~~next 12 to (1) mitigate a risk by not investigating outage insurance; (2) investigate alternative recovery mechanisms prior to seeking recovery from customers; and (3) meet our burden of proof because the filing lacked sufficient information demonstrating the prudency of the replacement power costs. We filed a motion for reconsideration of the decision with the MPSC. The matter is fully briefed and awaiting a decision by the MPSC.

~~Electric and Natural Gas Lost Revenue Adjustment Mechanism~~18 months.- In 2005, the MPSC approved an energy efficiency program, by which we recovered on an after-the-fact basis a portion of our fixed costs that would otherwise have been collected in kilowatt hour sales lost due to the implementation of energy saving measures. In an order issued in October 2013 related to our 2011/2012 electric supply tracker, the MPSC required us to lower the calculated lost revenue recovery and imposed a new burden of proof on us for future recovery. We appealed the October 2013 order to Montana District Court, which led to a docket being initiated in June 2014 by the MPSC to review lost revenue policy issues. In October 2015, the MPSC issued an order to eliminate the lost revenue adjustment mechanism prospectively effective December 1, 2015.

Based on the October 2013 MPSC order, for the period July 1, 2012 through November 30, 2015, we recognized $7.1 million of lost revenues for each annual electric supply tracker period and deferred the remaining $14.2 million of efficiency efforts collected through the trackers pending final approval of the open tracker filings. As discussed above, during the second quarter of 2016, we received final written orders resolving our prior period open tracker dockets. These orders allowed the recovery of lost revenues included in each tracker period. As a result, we recognized revenue deferred during the July 2012 - November 2015 periods of $14.2 million in the Condensed Consolidated Statement of Income for the three months ended June 30, 2016.

Hydro Compliance Filing

In December 2015, we submitted the required ~~hydro~~ compliance filing associated with our 2014 purchase of Montana hydroelectric (hydro) generation assets, to remove the Kerr Project from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In ~~January~~December 2016, the MPSC approved an interim adjustment to our hydro rates based on the compliance filing, and opened a separate contested docket requesting additional detail on the adjustment to rates due to the conveyance of the Kerr Project. The MPSC identified additional issues and requested information. A procedural schedule has been established and a hearing is scheduled for September 2016. We expect the MPSC to issueissued a final order ~~during~~in this filing reducing the ~~fourth quarter~~annual amount we are allowed to recover in hydro generation rates by approximately $1.2 million. In addition, in the final order, the MPSC included language requiring us to indicate by April 30, 2017, whether we intend to file a Montana electric rate case based on a 2016 test year.

On April 26, 2017, we filed our required annual report with the MPSC regarding 2016 results, which indicates we earned less than our authorized rate of ~~2016. Due~~return. At the same time, we also submitted a filing to the ~~timing of~~MPSC responsive to the hydro compliance order, indicating we do not expect to file an electric rate ~~adjustment, as of June 30,~~case in 2017 based on a 2016 test year. However, we ~~have deferred revenue of approximately $4.9 million that~~indicated we expect to ~~refund~~file a general electric rate case in 2018 based on a 2017 test year. In the hydro compliance order, the MPSC indicated that if we do not intend to ~~customers~~file a rate case in ~~2016.~~2017, the MPSC may require us to make an additional financial filing that would facilitate an assessment of whether the MPSC believes additional action would be required to fulfill its obligation to authorize just and reasonable rates.

FERC Filing - Dave Gates Generating Station at Mill Creek (DGGS)

In May 2016, we received an order from the Federal Energy Regulatory Commission (FERC) denying a May 2014 request for rehearing and requiring us to make refunds. The request for rehearing challenged a September 2012 FERC Administrative Law Judge's (ALJ) initial decision regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded that only a portion of these costs should be allocated to FERC jurisdictional customers. We had cumulative deferred ~~cumulative~~ revenue of approximately $27.3 million, consistent with the ALJ's initial decision, which was refunded to wholesale and choice customers in June 2016 in accordance with the FERC order.

In June 2016, we filed a petition for review of the FERC's May 2016 order with the United States Circuit Court of Appeals for the District of Columbia ~~Circuit.~~Circuit (D.C. Circuit). The ~~briefing schedule for this appeal has not been established.~~

~~The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. As of June 30, 2016, the DGGS net property, plant~~matter is fully briefed, and ~~equipment is approximately $152 million. DGGS previously provided only regulation service, which is the basis~~we are waiting for the ~~cost allocation in our previous MPSC and FERC filings. With the addition of owned hydro generation in November 2014, we are able~~Court to shift the utilization of DGGS to additional alternative uses, optimizing our generation portfolio. In support of our biennial electricity supply resource procurement plan that we filed with the MPSC in March 2016, we conductedset a portfolio optimization analysis to evaluate options to use DGGS in combination with other generation resources. This analysis indicates DGGS provides cost-effective products necessary to operate our Montana electricity portfolio, including regulation, load following, peaking services and other ancillary products such as contingency reserves, which should guide future cost recovery. The cost recovery of any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval.date for oral argument. We do not ~~believe an impairment loss is probable~~expect a decision in this matter until the fourth quarter of 2017, at ~~this time; however, we will continue to evaluate recovery of this asset in~~ the ~~future as facts and circumstances change.~~earliest.

(4) Income Taxes

~~The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in thousands):~~

Three Months Ended
June 30,
2016 2015
Income Before Income Taxes $ 38,516
$ 39,184

Income tax calculated at 35% federal statutory rate 13,481
35.0 % 13,715
35.0 %

Permanent or flow through adjustments:
State income, net of federal provisions (1,025 ) (2.7 ) 367
0.9
Flow-through repairs deductions (6,971 ) (18.1 ) (4,848 ) (12.4 )
Production tax credits (2,324 ) (6.0 ) (651 ) (1.7 )
Plant and depreciation of flow through items (246 ) (0.6 ) (245 ) (0.6 )
Prior year permanent return to accrual adjustments (128 ) (0.3 ) —
—
Other, net 160
0.4
(127 ) (0.2 )
(10,534 ) (27.3 ) (5,504 ) (14.0 )

Income Tax Expense $ 2,947
7.7 % $ 8,211
21.0 %

Six Months Ended
June 30,
2016 2015
Income Before Income Taxes $ 79,042
$ 100,625

Income tax calculated at 35% federal statutory rate 27,665
35.0 % 35,219
35.0 %

Permanent or flow through adjustments:
State income, net of federal provisions (2,125 ) (2.6 ) 528
0.6
Flow-through repairs deductions (13,645 ) (17.3 ) (14,461 ) (14.4 )
Production tax credits (5,099 ) (6.5 ) (1,912 ) (1.9 )
Plant and depreciation of flow through items (1,184 ) (1.5 ) (626 ) (0.6 )
Prior year permanent return to accrual adjustments (128 ) (0.2 ) —
—
Other, net (65 ) —
(521 ) (0.6 )
(22,246 ) (28.1 ) (16,992 ) (16.9 )

Income Tax Expense $ 5,419
6.9 % $ 18,227
18.1 %

We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production

tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.

The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in thousands):



	Three Months Ended June 30,
	2017					2016
Income Before Income Taxes	$	22,410				$	38,516

Income tax calculated at 35% federal statutory rate	7,844			35.0	%	13,481			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(492		)	(2.2	)	(1,025		)	(2.7	)
Flow-through repairs deductions	(4,753		)	(21.2	)	(6,971		)	(18.1	)
Production tax credits	(1,459		)	(6.5	)	(2,324		)	(6.0	)
Plant and depreciation of flow through items	(686		)	(3.1	)	(246		)	(0.6	)
Prior year permanent return to accrual adjustments	—			—		(128		)	(0.3	)
Other, net	126			0.6		160			0.4
	(7,264		)	(32.4	)	(10,534		)	(27.3	)

Income Tax Expense	$	580		2.6	%	$	2,947		7.7	%



	Six Months Ended June 30,
	2017					2016
Income Before Income Taxes	$	85,654				$	79,042

Income tax calculated at 35% federal statutory rate	29,979			35.0	%	27,665			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions (1)	(1,326		)	(1.5	)	(2,292		)	(2.9	)
Flow-through repairs deductions	(13,550		)	(15.8	)	(13,645		)	(17.3	)
Production tax credits	(5,290		)	(6.2	)	(5,099		)	(6.5	)
Plant and depreciation of flow through items	(2,126		)	(2.5	)	(1,184		)	(1.5	)
Share-based compensation (1)	(399		)	(0.5	)	(1,646		)	(2.1	)
Prior year permanent return to accrual adjustments	—			—		(128		)	(0.1	)
Other, net	(31		)	—		(65		)	—
	(22,722		)	(26.5	)	(24,059		)	(30.4	)

Income Tax Expense	$	7,257		8.5	%	$	3,606		4.6	%

(1) We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016, which resulted in the recognition of $1.8 million in excess tax benefits. In accordance with the guidance, the impact of this adoption is reflected as of January 1, 2016, and included in the state income, net of federal provisions, and share-based compensation lines, resulting in a reduction in tax expense for the six months ended June 30, 2016.

Uncertain Tax Positions

We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. We have unrecognized tax benefits of approximately ~~$91.0~~$84.4 million as of June 30, ~~2016~~2017, including approximately $~~66.8~~66.7 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the six months ended June 30, 2017 we recognized $0.3 million of expense for interest and penalties in the Condensed Consolidated Statements of Income. During the six months ended June 30, 2016, we recognized $0.3 million of expense for interest and penalties in the Condensed Consolidated Statements of Income. As of June 30, 2017 and December 31, 2016,, we had ~~$0.3~~$1.0 million and $0.7 million, respectively, of interest accrued in the Condensed Consolidated Balance Sheets. During the six months ended June 30, 2015, we did not recognize any expense for interest or penalties, and did not have any amounts accrued as of December 31, 2015, for the payment of interest and penalties.

Our federal tax returns from 2000 forward remain subject to examination by the Internal Revenue Service.

(5) Goodwill

We completed our annual goodwill impairment test as of April 1, ~~2016,~~2017, and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.

There were no changes in our goodwill during the six months ended June 30, ~~2016.~~2017. Goodwill by segment is as follows for both June 30, ~~2016~~2017 and December 31, ~~2015~~2016 (in thousands):



Electric	$	243,558
Natural gas	114,028
Total	$	357,586

(6) Comprehensive Income (Loss)

The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands):


	Three Months Ended															Three Months Ended
	June 30, 2016							June 30, 2015								June 30, 2017									June 30, 2016
	Before-Tax Amount		Tax Expense			Net-of-Tax Amount		Before-Tax Amount			Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Expense			Net-of-Tax Amount			Before-Tax Amount		Tax Expense			Net-of-Tax Amount
Foreign currency translation adjustment	$	8	$	—		$	8	$	(56	)	$	—	$	(56	)	$	(104	)	$	—		$	(104	)	$	8	$	—		$	8
Reclassification of net losses (gains) on derivative instruments	62		(25		)	37		(143		)	52		(91		)
Reclassification of net losses on derivative instruments																153			(60		)	93			62		(25		)	37
Other comprehensive income (loss)	$	70	$	(25	)	$	45	$	(199	)	$	52	$	(147	)	$	49		$	(60	)	$	(11	)	$	70	$	(25	)	$	45


	Six Months Ended																	Six Months Ended
	June 30, 2016									June 30, 2015								June 30, 2017									June 30, 2016
	Before-Tax Amount			Tax Expense			Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Expense			Net-of-Tax Amount			Before-Tax Amount			Tax Expense			Net-of-Tax Amount
Foreign currency translation adjustment	$	(110	)	$	—		$	(110	)	$	212		$	—	$	212		$	(53	)	$	—		$	(53	)	$	(110	)	$	—		$	(110	)
Reclassification of net losses (gains) on derivative instruments	124			(50		)	74			(286		)	106		(180		)
Reclassification of net losses on derivative instruments																		306			(120		)	186			124			(50		)	74
Other comprehensive income (loss)	$	14		$	(50	)	$	(36	)	$	(74	)	$	106	$	32		$	253		$	(120	)	$	133		$	14		$	(50	)	$	(36	)

Balances by classification included within accumulated other comprehensive loss (AOCL) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands):


	June 30, 2016			December 31, 2015			June 30, 2017			December 31, 2016
Foreign currency translation	$	1,245		$	1,355		$	1,327		$	1,380
Derivative instruments designated as cash flow hedges	(8,940		)	(9,014		)	(10,166		)	(10,352		)
Pension and postretirement medical plans	(937		)	(937		)
Postretirement medical plans							(742		)	(742		)
Accumulated other comprehensive loss	$	(8,632	)	$	(8,596	)	$	(9,581	)	$	(9,714	)

The following tables display the changes in AOCL by component, net of tax (in thousands):



		Three Months Ended
		June 30, 2017
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total
Beginning balance		$	(10,259	)	$	(742	)	$	1,431		(9,570		)
Other comprehensive loss before reclassifications		—			—			(104		)	(104		)
Amounts reclassified from AOCL	Interest Expense	93			—			—			93
Net current-period other comprehensive income (loss)		93			—			(104		)	(11		)
Ending balance		$	(10,166	)	$	(742	)	$	1,327		$	(9,581	)



		Three Months Ended
		June 30, 2016
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	(8,977	)	$	(937	)	$	1,237	(8,677		)
Other comprehensive income before reclassifications		—			—			8		8
Amounts reclassified from AOCL	Interest Expense	37			—			—		37
Net current-period other comprehensive income		37			—			8		45
Ending balance		$	(8,940	)	$	(937	)	$	1,245	$	(8,632	)

Three Months Ended
June 30, 2015
Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total
Beginning balance $ (8,405 ) $ (1,247 ) $ 1,065
(8,587 )
Other comprehensive loss before reclassifications —
—
(56 ) (56 )
Amounts reclassified from Accumulated Other Comprehensive Income (AOCI) Interest Expense (91 ) —
—
(91 )
Net current-period other comprehensive loss (91 ) —
(56 ) (147 )
Ending balance $ (8,496 ) $ (1,247 ) $ 1,009
$ (8,734 )



		Six Months Ended
		June 30, 2017
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total
Beginning balance		$	(10,352	)	(742		)	$	1,380		(9,714		)
Other comprehensive loss before reclassifications		—			—			(53		)	(53		)
Amounts reclassified from AOCL	Interest Expense	186			—			—			186
Net current-period other comprehensive income (loss)		186			—			(53		)	133
Ending balance		$	(10,166	)	$	(742	)	$	1,327		$	(9,581	)


		Six Months Ended													Six Months Ended
		June 30, 2016													June 30, 2016
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total			Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total
Beginning balance		$	(9,014	)	$	(937	)	$	1,355		(8,596		)		$	(9,014	)	(937		)	$	1,355		(8,596		)
Other comprehensive loss before reclassifications		—			—			(110		)	(110		)		—			—			(110		)	(110		)
Amounts reclassified from AOCL	Interest Expense	74			—			—			74			Interest Expense	74			—			—			74
Net current-period other comprehensive income (loss)		74			—			(110		)	(36		)		74			—			(110		)	(36		)
Ending balance		$	(8,940	)	$	(937	)	$	1,245		$	(8,632	)		$	(8,940	)	$	(937	)	$	1,245		$	(8,632	)

Six Months Ended
June 30, 2015
Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total
Beginning balance $ (8,316 ) $ (1,247 ) $ 797
(8,766 )
Other comprehensive income before reclassifications —
—
212
212
Amounts reclassified from AOCI Interest Expense (180 ) —
—
(180 )
Net current-period other comprehensive (loss) income (180 ) —
212
32
Ending balance $ (8,496 ) $ (1,247 ) $ 1,009
$ (8,734 )

(7) Risk Management and Hedging Activities

Nature of Our Business and Associated Risks

We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a portion of our electric and natural gas supply requirements. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

Objectives and Strategies for Using Derivatives

To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater price stability for consumers. ~~These commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by the applicable state regulatory commissions.~~ We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines.

In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.

Accounting for Derivative Instruments

We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale; cash flow hedge; fair value hedge; and mark-to-market. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.

Normal Purchases and Normal Sales

We have applied the normal purchase and normal sale scope exception (NPNS) to our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no unrealized amounts recorded in the Financial Statements at June 30, ~~2016~~2017 and December 31, ~~2015~~2016. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

Credit Risk

Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We limit credit risk in our commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.

We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties. We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: (1) Western Systems Power Pool agreements – standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements – standardized financial gas and electric

contracts; (3) North American Energy Standards Board agreements – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry.

Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions.

Interest Rate Swaps Designated as Cash Flow Hedges

We have previously used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. We have no interest rate swaps outstanding. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCL. We reclassify these gains from AOCL into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Financial Statements (in thousands):

Location of amount reclassified from AOCL to Income Amount Reclassified from AOCL into Income during the Six Months Ended June 30, 2016

Interest rate contracts Interest Expense $ 124

A ~~net~~ pre-tax loss of approximately ~~$14.8~~$16.8 million is remaining in AOCL as of June 30, ~~2016~~2017, and we expect to reclassify approximately ~~$0.3~~$0.6 million of ~~net~~ pre-tax ~~gains~~losses from AOCL into interest expense during the next twelve months. These amounts relate to terminated swaps.

(8) Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs.

Applicable accounting guidance establishes a hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:

Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities;

Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and

Level 3 – Significant inputs that are generally not observable from market activity.

We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. NPNS transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 7 - Risk Management and Hedging Activities for further discussion.

We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented.


	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Margin Cash Collateral Offset		Total Net Fair Value		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Margin Cash Collateral Offset		Total Net Fair Value
	(in thousands)										(in thousands)
June 30, 2016
June 30, 2017
Restricted cash	$	6,232	$	—	$	—	$	—	$	6,232	$	5,354	$	—	$	—	$	—	$	5,354
Rabbi trust investments	27,121		—		—		—		27,121		29,012		—		—		—		29,012
Total	$	33,353	$	—	$	—	$	—	$	33,353	$	34,366	$	—	$	—	$	—	$	34,366

December 31, 2015
December 31, 2016
Restricted cash	$	6,240	$	—	$	—	$	—	$	6,240	$	4,164	$	—	$	—	$	—	$	4,164
Rabbi trust investments	24,245		—		—		—		24,245		25,064		—		—		—		25,064
Total	$	30,485	$	—	$	—	$	—	$	30,485	$	29,228	$	—	$	—	$	—	$	29,228

Restricted cash represents amounts held in money market mutual funds. Rabbi trust investments represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets.

Financial Instruments

The estimated fair value of financial instruments is summarized as follows (in thousands):


	June 30, 2016				December 31, 2015				June 30, 2017			December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount	Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	1,773,714	$	1,976,889	$	1,768,183	$	1,844,974	1,793,797	$	1,898,482	$	1,793,338	$	1,852,052

Short-term borrowings consist of commercial paper and are not included in the table above as carrying value approximates fair value. The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange.

We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.

~~(9) Financing Activities~~

In June 2016, we issued $60 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.80% maturing in 2026. These bonds are secured by our electric and natural gas assets in South Dakota and were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended. Proceeds were used to redeem our 6.05%, $55 million South Dakota First Mortgage Bonds due 2018.

~~(10)~~(9) Segment Information

Our reportable business segments are primarily engaged in the electric and natural gas business. The remainder of our operations are presented as other, which primarily consists of unallocated corporate costs.

We evaluate the performance of these segments based on gross margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions.

Financial data for the business segments are as follows (in thousands):


Three Months Ended
June 30, 2016	Electric			Gas			Other			Eliminations		Total
June 30, 2017															Electric			Gas			Other			Eliminations		Total
Operating revenues	$	248,403		$	44,717		$	—		$	—	$	293,120		233,866			$	49,993		$	—		$	—	$	283,859
Cost of sales	72,165			9,528			—			—		81,693			70,146			13,854			—			—		84,000
Gross margin	176,238			35,189			—			—		211,427			163,720			36,139			—			—		199,859
Operating, general and administrative	51,568			20,585			426			—		72,579			54,086			20,206			896			—		75,188
Property and other taxes	27,322			7,883			3			—		35,208			30,909			8,569			3			—		39,481
Depreciation and depletion	32,544			7,346			8			—		39,898			34,105			7,382			8			—		41,495
Operating income (loss)	64,804			(625		)	(437		)	—		63,742			44,620			(18		)	(907		)	—		43,695
Interest expense	(24,119		)	(1,814		)	(488		)	—		(26,421		)	(21,064		)	(1,500		)	(844		)	—		(23,408		)
Other income	687			271			237			—		1,195			917			489			717			—		2,123
Income tax (expense) benefit	(3,331		)	1,278			(894		)	—		(2,947		)	(523		)	817			(874		)	—		(580		)
Net income (loss)	$	38,041		$	(890	)	$	(1,582	)	$	—	$	35,569		$	23,950		$	(212	)	$	(1,908	)	$	—	$	21,830
Total assets	$	4,221,293		$	1,080,065		$	6,248		—		$	5,307,606		$	4,439,694		$	1,114,426		$	2,812		—		$	5,556,932
Capital expenditures	$	57,938		$	11,990		$	—		—		$	69,928		$	55,995		$	11,609		$	—		—		$	67,604


Three Months Ended
June 30, 2015	Electric			Gas			Other			Eliminations		Total
June 30, 2016															Electric			Gas			Other			Eliminations		Total
Operating revenues	$	221,362		$	49,198		$	—		$	—	$	270,560		$	248,403		$	44,717		$	—		$	—	$	293,120
Cost of sales	65,918			13,609			—			—		79,527			72,165			9,528			—			—		81,693
Gross margin	155,444			35,589			—			—		191,033			176,238			35,189			—			—		211,427
Operating, general and administrative	60,838			21,800			(20,918		)	—		61,720			51,568			20,585			426			—		72,579
Property and other taxes	25,080			7,371			3			—		32,454			27,322			7,883			3			—		35,208
Depreciation and depletion	28,493			7,226			8			—		35,727			32,544			7,346			8			—		39,898
Operating income (loss)	41,033			(808		)	20,907			—		61,132			64,804			(625		)	(437		)	—		63,742
Interest expense	(19,748		)	(2,748		)	(447		)	—		(22,943		)	(24,119		)	(1,814		)	(488		)	—		(26,421		)
Other income (expense)	1,659			700			(1,364		)	—		995
Other income															687			271			237			—		1,195
Income tax (expense) benefit	(3,558		)	1,217			(5,870		)	—		(8,211		)	(3,331		)	1,278			(894		)	—		(2,947		)
Net income (loss)	$	19,386		$	(1,639	)	$	13,226		$	—	$	30,973		$	38,041		$	(890	)	$	(1,582	)	$	—	$	35,569
Total assets	$	3,994,221		1,057,958			$	7,889		$	—	$	5,060,068		$	4,221,293		$	1,080,065		$	6,248		$	—	$	5,307,606
Capital expenditures	$	63,926		10,706			$	—		$	—	$	74,632		$	57,938		$	11,990		$	—		$	—	$	69,928


Six Months Ended
June 30, 2016	Electric			Gas			Other			Eliminations		Total
June 30, 2017															Electric			Gas			Other			Eliminations		Total
Operating revenues	$	489,745		$	135,914		$	—		$	—	$	625,659		500,105			$	151,066		$	—		$	—	$	651,171
Cost of sales	155,789			41,338			—			—		197,127			155,531			48,286			—			—		203,817
Gross margin	333,956			94,576			—			—		428,532			344,574			102,780			—			—		447,354
Operating, general and administrative	107,011			42,497			2,932			—		152,440			112,705			41,835			1,610			—		156,150
Property and other taxes	54,751			15,872			6			—		70,629			62,070			17,333			6			—		79,409
Depreciation and depletion	65,065			14,707			16			—		79,788			68,175			14,765			16			—		82,956
Operating income (loss)	107,129			21,500			(2,954		)	—		125,675			101,624			28,847			(1,632		)	—		128,839
Interest expense	(46,174		)	(3,769		)	(987		)	—		(50,930		)	(42,101		)	(3,046		)	(1,661		)	—		(46,808		)
Other income	1,154			580			2,563			—		4,297			1,623			717			1,283			—		3,623
Income tax (expense) benefit	(4,346		)	(1,743		)	670			—		(5,419		)	(3,410		)	(6,134		)	2,287			—		(7,257		)
Net income (loss)	$	57,763		$	16,568		$	(708	)	$	—	$	73,623
Net income															$	57,736		$	20,384		$	277		$	—	$	78,397
Total assets	$	4,221,293		$	1,080,065		$	6,248		—		$	5,307,606		$	4,439,694		$	1,114,426		$	2,812		—		$	5,556,932
Capital expenditures	$	99,563		$	21,683		$	—		—		$	121,246		$	97,036		$	22,087		$	—		—		$	119,123


Six Months Ended
June 30, 2015	Electric			Gas			Other			Eliminations		Total
June 30, 2016															Electric			Gas			Other			Eliminations		Total
Operating revenues	$	457,408		$	159,163		$	—		$	—	$	616,571		$	489,745		$	135,914		$	—		$	—	$	625,659
Cost of sales	129,837			62,081			—			—		191,918			155,789			41,338			—			—		197,127
Gross margin	327,571			97,082			—			—		424,653			333,956			94,576			—			—		428,532
Operating, general and administrative	120,893			43,711			(21,761		)	—		142,843			107,011			42,497			2,932			—		152,440
Property and other taxes	50,339			14,896			6			—		65,241			54,751			15,872			6			—		70,629
Depreciation and depletion	57,047			14,482			17			—		71,546			65,065			14,707			16			—		79,788
Operating income	99,292			23,993			21,738			—		145,023
Operating income (loss)															107,129			21,500			(2,954		)	—		125,675
Interest expense	(39,446		)	(5,742		)	(870		)	—		(46,058		)	(46,174		)	(3,769		)	(987		)	—		(50,930		)
Other income (expense)	2,941			842			(2,123		)	—		1,660
Income tax expense	(9,811		)	(3,504		)	(4,912		)	—		(18,227		)
Other income															1,154			580			2,563			—		4,297
Income tax (expense) benefit (1)															(4,346		)	(1,743		)	2,483			—		(3,606		)
Net income(1)	$	52,976		$	15,589		$	13,833		$	—	$	82,398		$	57,763		$	16,568		$	1,105		$	—	$	75,436
Total assets	$	3,994,221		1,057,958			$	7,889		$	—	$	5,060,068		$	4,221,293		$	1,080,065		$	6,248		$	—	$	5,307,606
Capital expenditures	$	113,987		17,183			$	—		$	—	$	131,170		$	99,563		$	21,683		$	—		$	—	$	121,246

______________

(1) We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016, which resulted in the recognition of $1.8 million in excess tax benefits. In accordance with the guidance, the $1.8 million impact of this adoption is reflected as of January 1, 2016, which resulted in an increase in net income for the six months ended June 30, 2016 above.

~~(11)~~(10) Earnings Per Share

Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of common stock equivalent shares that could occur if all unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested performance share awards. Average shares used in computing the basic and diluted earnings per share are as follows:


	Three Months Ended		Three Months Ended
	June 30, 2016	June 30, 2015	June 30, 2017	June 30, 2016
Basic computation	48,308,656	47,043,735	48,450,639	48,308,656
Dilutive effect of:
Performance share awards (1)	66,787	243,961	130,772	76,877

Diluted computation	48,375,443	47,287,696	48,581,411	48,385,533


	Six Months Ended		Six Months Ended
	June 30, 2016	June 30, 2015	June 30, 2017	June 30, 2016
Basic computation	48,275,482	47,010,546	48,418,368	48,275,482
Dilutive effect of:
Performance share awards (1)	66,621	247,696	129,383	76,737

Diluted computation	48,342,103	47,258,242	48,547,751	48,352,219

~~______________~~_______

(1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.

We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016. Under this ASU, the assumed proceeds from applying the treasury stock method when computing earnings per share no longer includes the amount of excess tax benefits or deficiencies that used to be recognized as additional paid-in capital. This change in the treasury stock method was made on a prospective basis, with adjustments reflected as of January 1, 2016. The changes to the treasury stock method required by this ASU increased dilutive shares by 10,090 and 10,116 for the three and six months ended June 30, 2016.

~~(12)~~(11) Employee Benefit Plans

Net periodic benefit cost (income) for our pension and other postretirement plans consists of the following (in thousands):


	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,						Three Months Ended June 30,						Three Months Ended June 30,						Three Months Ended June 30,
	2016			2015			2016			2015			2017			2016			2017			2016
Components of Net Periodic Benefit Cost (Income)
Service cost	$	2,941		$	2,718		$	116		$	134		$	2,367		$	2,941		$	100		$	116
Interest cost	6,539			6,545			196			210			6,388			6,539			178			196
Expected return on plan assets	(7,043		)	(7,861		)	(260		)	(242		)	(5,974		)	(7,043		)	(211		)	(260		)
Amortization of prior service cost	61			61			(470		)	(441		)	—			61			(470		)	(470		)
Recognized actuarial loss	2,478			2,699			71			112			1,944			2,478			81			71
Net Periodic Benefit Cost (Income)	$	4,976		$	4,162		$	(347	)	$	(227	)	$	4,725		$	4,976		$	(322	)	$	(347	)


	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,						Six Months Ended June 30,						Six Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015			2017			2016			2017			2016
Components of Net Periodic Benefit Cost (Income)
Service cost	5,880			$	6,181		$	246		$	263		$	5,497		$	5,880		$	228		$	246
Interest cost	13,105			13,087			398			393			12,817			13,105			358			398
Expected return on plan assets	(14,124		)	(15,781		)	(521		)	(485		)	(11,982		)	(14,124		)	(424		)	(521		)
Amortization of prior service cost	123			123			(941		)	(941		)	2			123			(941		)	(941		)
Recognized actuarial loss	4,944			5,317			158			193			3,919			4,944			159			158
Net Periodic Benefit Cost (Income)	$	9,928		$	8,927		$	(660	)	$	(577	)	$	10,253		$	9,928		$	(620	)	$	(660	)

~~(13)~~(12) Commitments and Contingencies



ENVIRONMENTAL LIABILITIES AND REGULATION

Environmental Matters

The operation of electric generating, transmission and distribution facilities, and gas gathering, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.

Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, the majority of our environmental reserve relates to the remediation of former manufactured gas plant sites owned by us and is estimated to range between ~~$27~~$27.9 million to ~~$32~~$32.6 million. As of June 30, ~~2016,~~2017, we have a reserve of approximately ~~$30.9~~$30.6 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred.

Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or results of operations.

Manufactured Gas Plants - Approximately ~~$24.3~~$23.8 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies, ~~and~~ implementing remedial actions ~~at the Aberdeen site~~ pursuant to work plans approved by the South Dakota Department of Environment and Natural ~~Resources.~~Resources, and conducting ongoing monitoring and operation and maintenance activities. As of June 30, ~~2016,~~2017, the reserve for remediation costs at this site is approximately ~~$11.4~~$10.4 million, and we estimate that approximately ~~$6.7~~$5.9 million of this amount will be incurred during the next five years.

We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.

In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. The Butte and Helena sites, both listed as high priority sites on Montana's state superfund list, were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. In August 2016, the MDEQ ~~requested additional information~~sent us a Notice of Potential Liability and Request for Remedial Action regarding the Helena site. At MDEQ's direction, a soil vapor analysis plan for the two buildings located on the Helena site was submitted in January 2017. MDEQ reviewed the results of the analysis and indicated that work should be postponed until the winter of 2017-2018 to be integrated in an overall remediation plan for the Helena site. We expect to continue soil and groundwater sampling at the Helena site. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte ~~and Helena sites.~~site.

An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. Monitoring wells have been installed and groundwater is monitored semiannually. At the request of Missoula Valley Water Quality District (MVWQD), a draft risk assessment was prepared for the Missoula site and presented to the ~~Missoula County Water Quality Board (MCWQB). The MCWQB deferred all decision making to~~MVWQD. We and the ~~MDEQ, but suggested~~MVWQD agreed additional site ~~delineation. Additional delineation~~investigation work ~~began~~is appropriate. Analytical results from an October 2016 sampling exceeded the Montana Maximum Contaminant Level for benzene and/or total cyanide in ~~December 2015 and has continued~~certain monitoring wells. These results were forwarded to MVWQD which shared the same with the MDEQ. MDEQ requested that MVWQD file a formal complaint with MDEQ's Enforcement Division, which MVWQD filed in ~~2016. The result~~July 2017. This is expected to prompt MDEQ to reevaluate its position concerning listing the Missoula site on the State of Montana's superfund list. New landowners purchased a portion of the ~~additional delineation work may lead~~Missoula site using funding provided by a third party. The terms of the funding require the new landowners to ~~amending~~address environmental issues. The new landowners contacted us and have requested a meeting to address concerns. After researching historical ownership we have identified another potentially responsible party with whom we have initiated communications regarding the ~~risk assessment and/or development of a remedial alternatives report followed by implementation of a remedy.~~site. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula ~~site or if any additional actions beyond monitored natural attenuation will be required.~~site.

Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of emissions of greenhouse gases (GHG) including, most significantly, carbon dioxide ~~(CO2)~~(CO₂). These actions include legislative proposals, Executive and Environmental Protection Agency (EPA) actions at the federal level, actions at the state level, and private party litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their level of GHG emissions. We have joint ownership interests in four coal-fired electric generating plants, all of which are operated by other companies. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.

While numerous bills have been introduced that address climate change from different perspectives, including through direct regulation of GHG emissions, the establishment of cap and trade programs and the establishment of Federal renewable portfolio standards, Congress has not passed any federal climate change legislation and we cannot predict the timing or form of any potential legislation. In the absence of such legislation, EPA is presently regulating new and existing sources of GHG ~~emissions.~~emissions through regulations. EPA is currently reviewing its existing regulations as a result of an Executive Order issued by President Trump on March 28, 2017 (the Executive Order) instructing all federal agencies to review all regulations and other policies (specifically including the Clean Power Plan , which is discussed in further detail below) that burden the development or use of domestically produced energy resources and suspend, revise or rescind those that pose an undue burden beyond that required to protect the public interest.

~~On August 3, 2015,~~One of the regulations that the EPA ~~released for publication in~~was instructed to review under the ~~Federal Register,~~Executive Order is the final standards of performance toissued by EPA on August 3, 2015 which limit GHG emissions from new, modified and reconstructed fossil fuel generating units and from newly constructed and reconstructed natural gas combined cycle (NGCC) units. The standards reflect the degree of emission limitations achievable through the application of the best system of emission reduction that the EPA determined has been demonstrated for each type of unit.

~~In a separate action~~Another regulation that ~~also affects power plants, on August 3, 2015,~~ the EPA ~~released~~was instructed to review pursuant to the Executive Order is its final ~~rule~~regulation establishing GHG performance standards for existing power plants under Clean Air Act Section 111(d) ~~(the~~, which was published in October, 2015, and is referred to as the Clean Power Plan ~~or CPP)~~(CPP). The CPP establishes CO₂CO2 emission performance standards for existing electric utility steam generating units and NGCC units. ~~States~~

Under the CPP, states may develop implementation plans for affected units to meet the individual state GHG emission reduction targets established in the CPP or may adopt a federal plan. The ~~EPA has given states the option to develop compliance plans for annual rate-based~~CPP may require reductions ~~(pounds per megawatt hour (MWH)) or mass-based tonnage limits for~~in CO₂~~. The 2030 rate-based requirement for all existing affected generating units~~ emissions from

2012 emission levels of up to 38.4 percent in South Dakota and Montana is 1,167 and 1,305 pounds per MWH, respectively. The rate-based approach requires a 38.4 percent reduction in South Dakota and a 47.4 percent reduction in Montana from 2012 levels by 2030. The mass-based approach for existing units in South Dakota requires a 30.9 percent decrease by 2030, while in Montana the mass-based approach requires a 41 percent decrease by 2030. States are required to submit initial plans for achieving GHG emission standards to EPA by September 2016, but may seek additional time to finalize State plans by September 2018. The initial performance period for compliance would commence in 2022, with full implementation by 2030. The EPA also indicated that states may establish emission trading programs to facilitate compliance with the CPP and provides three options: an emission rate trading program that would allow the trading of emission reduction credits equal to one MWH of emission free generation; a mass-based program that would allow trading of allowances with an allowance equal to one short ton of CO₂~~; and a state measures program that would allow intra-state trading to achieve the state-wide average emission rate.~~

On August 3, 2015, the EPA also proposed a federal plan that would be imposed if a state fails to submit a satisfactory plan under the CPP. The federal plan proposal includes a "model trading rule" that describes how the EPA would establish an emission trading program as part of the federal plan to allow affected units to comply with the emission rate requirements. EPA proposed both an emission rate trading plan and a mass-based trading plan and indicated that the final federal rule will elect one

~~of the two options. The EPA has indicated that it intends to finalize both the federal plan and the model trading rules in the summer of 2016.~~

~~The CPP reduction of~~ 47.4 percent in ~~carbon dioxide emissions in~~ Montana by ~~2030 is~~2030. Neither South Dakota nor Montana has submitted implementation plans to date.

Following the greatest reduction target among the lower 48 states, according to a nationwide analysis. Our Montana generation portfolio emits less carbon on average than the EPA's 2030 target due to investments we made prior to 2013 in carbon-free generation resources. However, the CPP's target reduction is applied on a statewide basis, and investments made prior to 2012 are not counted in the CPP's 2030 target. We asked the University of Montana’s Bureau of Business and Economic Research (BBER) to study the potential impactsissuance of the CPP, ~~across Montana. The BBER study looked at the implications of closing all four of the generating units that comprise the Colstrip facility~~judicial appeals were filed in southeast Montana as a scenario for complying with the federal rule. The study's conclusions describe the likely loss of jobs and population, the decline in the local and state tax base, the impact on businesses statewide, and the closure's impact on electric reliability and affordability. The electricity produced at Colstrip Unit 4 represents approximately 25 percent of our customer needs. Closing all four Colstrip units would lead to higher utility rates in order to replace the base-load generation that currently is provided by Colstrip. Closing all four Colstrip units would also create significant issues with the transmission grid that serves Montana, and we would lose transmission revenues that are credited to and lower electric customer bills.

On October 23, 2015, the same date the CPP was published in the Federal Register, we along with other utilities, trade groups, coal producers, and labor and business organizations, filed Petitions for Review of the CPP with the United States Court of Appeals for the District of Columbia Circuit. Accompanying these Petitions for Review were Motions to Stay the implementation of the CPP. On January 21, 2016, the U.S. Court of Appeals for the District of Columbia denied the requests for stay but ordered expedited briefingCircuit (D.C. Circuit), including an appeal by us filed on ~~the merits. On January 26, 2016, 29 states and state agencies asked the U.S.~~October 23, 2015. The United States Supreme Court to issue an immediate stay of the CPP. On January 27, 2016, 60 utilities and allied petitioners also requested the U.S. Supreme Court to immediately stay the CPP, and we were among the utilities seeking(Supreme Court) issued a ~~stay. On February 9, 2016, the U.S. Supreme Court entered an order staying the CPP. The~~ stay of the CPP ~~will remain in place until~~on February 9, 2016 pending resolution of the ~~U.S.~~appeals by the D.C. Circuit and possibly the Supreme ~~Court either denies a petition for certiorari following the U.S. Court of Appeals’ decision~~Court. Oral argument on the ~~substantive challenges~~case was held in September 2016. In April 2017, the D.C. Circuit granted the EPA's request to hold the case in abeyance pursuant to the ~~CPP, if one is submitted, or until the U.S. Supreme Court enters judgment following grant~~Executive Order, but only for a period of a petition for certiorari. On May 16, 2016, the U.S. Court of Appeals for the District of Columbia entered an order declaring the challenge to the CPP would be reviewed en banc, rather than by a three judge panel, and delayed oral argument until September 2016. An initial ruling on the challenge is not expected until early 2017, and the U.S. Supreme Court decision on challenges to the CPP is not anticipated until mid-2017, if not early 2018.sixty days.

~~On December 22, 2015 we also~~In addition, administrative requests for reconsideration of the CPP were filed ~~an administrative Petition for Reconsideration~~ with the EPA, ~~requesting that it~~including one filed by us in December 2015. We requested the EPA reconsider the CPP, in part, on the grounds that the CO₂ reductions in the CPP applicable to Montana were substantially greater ~~in Montana~~ than in the ~~proposed rule. We~~reductions the EPA had originally proposed. The EPA denied the petition for reconsideration on January 11, 2017, and we appealed that denial to the D.C. Circuit on March 13, 2017. The EPA has also requested ~~EPA stay~~that this case be held in abeyance. No action has been taken by the ~~CPP while it considered our Petition for Reconsideration. At~~D.C. Circuit in this ~~time, the EPA has taken no action on the Petition for Reconsideration or stay request.~~case.

~~On June 23, 2014,~~There is no certainty as to what, if any, action the ~~U.S. Supreme Court struck down~~D.C. Circuit may take in either of these two cases before the ~~EPA's Tailoring Rule, which limited~~EPA takes action to address the sources subject to GHG permitting requirements to the largest fossil-fueled power plants, indicating that EPA had exceeded its authority under the Clean Air Act by "rewriting unambiguous statutory terms." However, the decision affirmed EPA's ability to regulate GHG emissions from sources already subject to regulation under the prevention of significant deterioration program, which includes most electric generating units.

Requirements to reduce GHG emissions could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Although there continues to be proposed legislation and regulations that affect GHG emissions from power plants, technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. In addition, physical impacts of climate change may present potential risks for severe weather, such as droughts, floods and tornadoes, in the locations where we operate or have interests.CPP.

WeIf the CPP survives the Executive Order, the legal challenges described above, and is implemented as written, it could result in significant additional compliance costs that would affect our future results of operations and financial position if such costs are ~~evaluating the implications of these rules and technology available to achieve the CO~~₂ ~~emission performance standards.~~not recovered through regulated rates. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from the ~~final rules~~CPP that, in our view, disproportionately ~~impact~~impacts customers in our ~~region, and to seek relief from the final compliance requirements.~~region. We cannot predict the ultimate outcome of these matters or what our obligations might be under the state compliance plans with any degree of certainty until they are finalized; however, complying with the ~~carbon~~CO₂ emission performance standards in the CPP, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of our jointly owned facilities or for individual owners to participate in their proportionate ownership of the coal-fired generating units. This could lead to significant impacts to customer rates for recovery of plant improvements and / or closure

related costs and costs to procure replacement power. In addition, these changes could impact system reliability due to changes in generation sources.

In addition, future additional requirements to reduce GHG emissions could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Technology to efficiently capture, remove and/or sequester such GHG emissions may not be available within a timeframe consistent with the implementation of any such requirements. Physical impacts of climate change also may present potential risks for severe weather, such as droughts, fires, floods, ice storms and tornadoes, in the locations where we operate or have interests. These potential risks may impact costs for electric and natural gas supply and maintenance of generation, distribution, and transmission facilities.

Water Intakes and Discharges - Section 316(b) of the Federal Clean Water Act requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best technology available (BTA)” for minimizing environmental impacts. In May 2014, the EPA issued a final rule applicable to facilities that withdraw at least 2 million gallons per day of cooling water from waters of the US and use at least 25 percent of the water exclusively for cooling purposes. The final rule, which became effective in October 2014, gives options for meeting BTA, and provides a flexible compliance approach. Under the rule, permits required for existing facilities will be developed by the individual states and additional capital and/or increased operating costs may be required to comply with future water permit requirements. Challenges to the final cooling water intake rule filed by industry and environmental groups are under review in the ~~Second Circuit~~United States Court of ~~Appeals.~~Appeals for the Second Circuit.

In November 2015, the EPA published final regulations on effluent limitations for power plant wastewater discharges, including mercury, arsenic, lead and selenium. The rule became effective in January 2016. Some of the new requirements for existing power plants would be phased in starting in 2018 with full implementation of the rule by 2023. The EPA rule estimates that 12 percent of the steam electric power plants in the U.S. will have to make new investments to meet the requirements of the new effluent limitation regulations. Challenges to the final rule have been filed in the ~~Fifth Circuit~~United States Court of Appeals ~~indicating~~for the Fifth Circuit, asserting that the EPA underestimated compliance costs. It is too early to determine whether the impacts of these rules will be material.

Clean Air Act Rules and Associated Emission Control Equipment Expenditures - The EPA has proposed or issued a number of rules under different provisions of the Clean Air Act that could require the installation of emission control equipment at the generation plants in which we have joint ownership.

In December 2011, the EPA issued a final rule relating to Mercury and Air Toxics Standards (MATS). Among other things, the MATS set stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. The rule was challenged by industry groups and states, and was upheld by the D.C. Circuit ~~Court~~ in April 2014. The decision was appealed to the Supreme Court and in June 2015, the Supreme Court issued an opinion that the EPA did not properly consider the costs to industry when making the requisite “appropriate and necessary” determination as part of its analysis in connection with the issuance of the MATS rule. The Supreme Court remanded the case back to the ~~U.S. Court of Appeals for the District of Columbia~~D.C. Circuit, and the D.C. Circuit remanded, without vacatur, the MATS rule to the EPA, leaving the rule in place. In April 2016, the EPA published its final supplemental finding that it is "appropriate and necessary" to regulate coal and oil-fired units under Section 112 of the Clean Air Act. Although industry and trade associations have filed a lawsuit in the D.C. Circuit challenging the EPA's supplemental finding and the D.C. Circuit recently delayed oral argument in the case at the request of the Trump administration, installation or upgrading of relevant environmental controls at our affected plants is complete and we are controlling emissions of mercury under the state and Federal MATS rules.

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to reduce emissions from electric generating units that interfere with the ability of downwind states to achieve ambient air quality standards. Under CSAPR, significant reductions in emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) were to be required in certain states beginning in 2012. In April 2014 the Supreme Court reversed and remanded the 2012 decision of the U.S. Court of Appeals for the D.C. Circuit that had vacated the CSAPR. In December, 2015 EPA published a proposed update to the CSAPR rule. Litigation of the remaining CSAPR lawsuits is pending.

In October 2013, the Supreme Court denied certiorari in Luminant Generation Co v. EPA, which challenged the EPA’s current approach to regulating air emissions during startup, shutdown and malfunction (SSM) events. As a result, fossil fuel power plants may need to address SSM in their permits to reduce the risk of enforcement or citizen actions.

The Clean Air Visibility Rule was issued by the EPA in June 2005, to address regional haze in national parks and wilderness areas across the United States. The Clean Air Visibility Rule requires the installation and operation of Best Available Retrofit Technology (BART) to achieve emissions reductions from designated sources (including certain electric generating units) that are deemed to cause or contribute to visibility impairment in 'Class I' areas.

In September 2012, a final Federal Implementation Plan for Montana was published in the Federal Register to address regional haze. ~~As finalized,~~The plan does not require Colstrip Units 3 and 4 ~~do not have~~ to improve removal efficiency for pollutants that contribute to regional haze. By 2018, Montana, or EPA, must develop a revised plan that demonstrates reasonable progress toward eliminating man made emissions of visibility impairing pollutants, which could impact Colstrip Unit 4. In November 2012, PPL Montana (now Talen ~~Montana)~~Montana, LLC) (Talen), the operator of Colstrip, as well as environmental groups (National Parks Conservation

Association, Montana Environmental Information Center (MEIC), and Sierra Club) jointly filed a petition for review of the Federal Implementation Plan in the ~~U.S.~~United States Court of Appeals for the Ninth ~~Circuit. Montana Environmental Information Center (MEIC)~~Circuit (Ninth Circuit). MEIC and Sierra Club challenged the EPA's decision not to require any emissions reductions from Colstrip Units 3 and 4. In June 2015, ~~the U.S. Court of Appeals for~~ the Ninth Circuit rejected the challengers’ contention that the EPA should have required additional pollution-reduction technologies on Unit 4 beyond those in the regulations and the matter is back in EPA Region 8 for action.

On January 10, 2017, the EPA published amendments to the requirements under the Clean Air Act for state plans for protection of visibility. Among other things, these amendments revised the process and requirements for the state implementation plans and extended the due date for the next periodic comprehensive regional haze state implementation plan revisions from 2018 to 2021. Therefore, by 2021, Montana, or EPA, must develop a revised plan that demonstrates reasonable progress toward eliminating man-made emissions of visibility impairing pollutants, which could impact Colstrip Unit 4. On March 13, 2017, we filed a Petition for Review of these amendments with the D.C. Circuit. On March 15, 2017, our petition was consolidated with other petitions challenging the final rule.

Jointly Owned Plants - We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are or may become subject to the various regulations discussed above that have been issued or proposed. ~~Each state is required by~~

Regarding the CPP, to submit a satisfactory plan to EPA by September 2018. The state plans will determine whether we will have to meet rate-based or mass-based requirements and, if the state adopts a mass-based plan, the number of vintages of allowances that will be allocated to our facilities. Until the plans are submitted, or a federal plan is imposed,as discussed above, we cannot predict the impact of the CPP on ~~us. In addition, compliance~~NorthWestern until there is a definitive judicial decision or administrative action by the EPA to withdraw or significantly change the CPP.

Compliance with the final rule on Water Intakes and Discharges discussed above, which became effective in January 2016, isdid not ~~expected to~~ have a significant impact at any of our jointly owned facilities.

North Dakota. The North Dakota Regional Haze ~~SIP~~state implementation plan requires the Coyote generating facility, in which we have 10% ownership, to reduce its ~~NOx~~nitrogen oxide (NOx) emissions by July 2018. In 2016, Coyote ~~is in the process~~completed installation of ~~installing~~ control equipment to ~~limit its~~maintain compliance with the lower NOx emissions toof 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and ~~shutdown, with the project expected to be operational in the third quarter of 2016.~~shutdown. The cost of the control equipment iswas not significant.

Montana. Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is subject to EPA's coal combustion residual rule. A compliance plan has been developed and is in the initial stages of implementation. The current estimate of the total project cost is approximately $90.0 million (our share is 30%) over the remaining life of the facility.

~~See 'Legal Proceedings - Colstrip Litigation' below for discussion of Sierra Club litigation.~~

Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.

We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:

We may not know all sites for which we are alleged or will be found to be responsible for remediation; and

Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.

LEGAL PROCEEDINGS

~~Colstrip Litigation~~

On March 6, 2013, the Sierra Club and the MEIC (Plaintiffs) filed suit in the United States District Court for the District of Montana (Court) against the six individual owners of the Colstrip Generating Station (Colstrip), including us, as well as Talen Montana (Talen), the operator or managing agent of the station. Colstrip consists of four coal fired generating units. Colstrip Units 1 and 2 are older than Units 3 and 4. We do not have an ownership interest in Units 1 and 2. We have a 30 percent joint interest in Unit 4 and a reciprocal sharing agreement with Talen regarding the operation Colstrip Units 3 and 4, in which each party receives 15% of the respective combined output of the units and is responsible for 15 percent of the respective operating and construction costs, regardless of whether a particular cost is specified to Colstrip Unit 3 or Unit 4.

On September 27, 2013, Plaintiffs filed an Amended Complaint for Injunctive and Declaratory Relief that dropped claims associated with projects completed before 2001, Title V claims and the opacity claims. The Amended Complaint alleged a total of 23 claims covering 64 projects.

In the Amended Complaint, Plaintiffs identified physical changes made at Colstrip between 2001 and 2012, that Plaintiffs allege (a) have increased emissions of SO2, NOx and particulate matter and (b) were “major modifications” subject to permitting requirements under the Clean Air Act. They also alleged violations of the requirements related to Part 70 Operating Permits.

In 2013, the Colstrip owners and operator filed partial motions to dismiss. On September 12, 2013, Plaintiffs filed a motion for partial summary judgment as to the applicable method for calculating emissions increases from modifications.

The parties filed a joint notice (Notice) on April 21, 2014, that advised the Court of Plaintiffs’ intent to file a Second Amended Complaint which dropped claims relating to 52 projects, and added one additional project. On May 6, 2014, the Court held oral argument on Defendants' motion to dismiss and on Plaintiffs’ motion for summary judgment on the applicable legal standard. On May 22, 2014, the United States Magistrate Judge (Magistrate) issued findings and recommendations, which denied Plaintiffs’ motion for summary judgment and denied most of the Colstrip owners’ motions to dismiss, but dismissed seven of Plaintiffs’ “best available control technology” claims and dismissed two of Plaintiffs' claims for injunctive relief. The Plaintiffs filed an objection to the Magistrate's findings and recommendations with the Court, and on August 13, 2014, the Court adopted the Magistrate's findings and conclusions.

On August 27, 2014, the Plaintiffs filed their Second Amended Complaint, which alleged a total of 13 claims covering eight projects and seeks injunctive and declaratory relief, civil penalties (including $100,000 of civil penalties to be used for beneficial environmental projects), and recovery of their attorney fees. Defendants filed their Answer to the Second Amended Complaint on September 26, 2014. Since filing the Second Amended Complaint, Plaintiffs have indicated that they are no longer pursuing a number of claims and projects thereby reducing their total claims to eight relating to four projects. The parties filed motions for summary judgment and briefs in support with regard to issues affecting the remaining claims.

On December 1, 2015, the Court held oral argument on all pending motions for summary judgment, and on December 31, 2015, the Magistrate issued findings and recommendations which (a) denied Plaintiffs’ motion for partial summary judgment regarding routine maintenance, repair and replacement; (b) denied Plaintiffs’ motion for partial summary judgment that the redesign projects for the Unit 1 and 4 turbines and the Unit 1 economizer were not “like kind replacements”; (c) granted Defendants’ motion for partial summary judgment regarding Plaintiffs’ use of the “actual-to-potential” emissions test; (d) granted in part and denied in part Plaintiffs’ motion for partial summary judgment regarding the allowable period from which to select a baseline for the Unit 3 reheater project; (e) granted in part and denied in part Defendants’ motion for partial summary judgment on baseline selection; and (f) granted Defendants’ motion for partial summary judgment on emissions calculations for alleged aggregated turbine and safety valve project. Plaintiffs filed objections to the Magistrate’s findings and recommendations on January 19, 2016, and Defendants filed their response on February 5, 2016.

The Court has not ruled on the Magistrate’s proposed findings and recommendations and the matter was scheduled to go to a bench trial on May 31, 2016. However, on April 26, 2016, the parties filed a joint motion to vacate the May 31, 2016, trial date and to stay all deadlines, to allow the parties to settle the litigation.

The parties lodged a proposed consent decree with the Court on July 12, 2016. The consent decree would dismiss all of the claims against all units, including Colstrip Unit 4, the only unit in which we have an ownership interest, and provides no shut-down date for Units 3 and 4. On the other hand, the consent decree provides that Units 1 and 2 must be shut down by July 1, 2022. Units 1 and 2 are owned solely by Talen and Puget Sound Energy. We had no role in the decisions regarding Units 1 and 2 as we have no ownership interest in those units.

If the Court enters the consent decree, all claims raised by plaintiffs against all four Colstrip units will be resolved. The EPA and the Department of Justice (DOJ) have 45 days from July 12, 2016, to comment on the consent decree or intervene of right. Following the 45-day period, the parties will seek approval and entry of the consent decree or will take other appropriate actions should there be any material comments on the consent decree by the United States or if the United States intervenes. The consent decree permits parties to petition the Court for costs and attorneys’ fees within 30 days after the Court enters the consent decree. We intend to seek attorneys’ fees and costs from the Sierra Club and the MEIC.

The six owners of Colstrip currently share the operating costs pursuant to the terms of an operating agreement among the owners of Units 3 and 4 and a common facility agreement among the owners of all four units. If Units 1 and 2 discontinue operation, we anticipate incurring incremental operating costs with respect to our interest in Unit 4. However, we do not anticipate that this increase will be material to our financial results.

In the event the Court does not enter the consent decree, we intend to continue to vigorously defend this lawsuit and cannot predict an outcome, nor is it reasonably possible to estimate the amount or range of loss, if any, that would be associated with an adverse decision.

Billings, Montana Refinery Outage Claim

In August 2014, we received a letter from the ExxonMobil refinery in Billings, Montana claiming that it had sustained approximately $48.5 million in damages as a result of a January 2014 electrical outage. In December 2015, ~~Exxon~~ExxonMobil increased the estimated losses related to that incident to approximately $61.7 million. On January 13, 2016, a second electrical outage shut down the ExxonMobil refinery. On January 22, 2016, ExxonMobil filed suit against NorthWestern in U.S. District Court in Billings, Montana, seeking unspecified compensatory and punitive damages arising from both outages. ExxonMobil currently claims property damages and economic losses of at least $108.0 million. We dispute ExxonMobil’s claims and intend to vigorously defend this lawsuit. We have reported the refinery's claims and lawsuit to our liability insurance carriers under our liability insurance coverage, which has a $2.0 million per occurrence retention. We also have brought third-party complaints against the City of Billings and General Electric International, Inc. alleging that they are responsible in whole or in part for the outages. ~~This matter is in the initial stages and we cannot~~We are not currently able to predict an outcome or estimate the amount or range of loss that would be associated with an adverse result.

Pacific Northwest Solar Litigation

Pacific Northwest Solar, LLC (PNWS) is an Oregon solar QF developer with which we began negotiating in early 2016 to purchase capacity and energy at our avoided cost under the QF-1 option 1(a) tariff standard rates in accordance with PURPA as implemented by the FERC and the MPSC.

On June 16, 2016, however, the MPSC entered a Notice of Commission Action (MPSC Notice) suspending the availability of QF-1 option 1(a) standard rates for solar projects greater than 100 kW, which included the various projects proposed by PNWS. The MPSC exempted from the suspension any contracts with solar QFs greater than 100 kW, but no larger than 3 MW, at the standard tariff rate, if prior to the date of the MPSC Notice, the QF had submitted a signed power purchase agreement and had executed an interconnection agreement. PNWS had not obtained interconnection agreements for any of its projects as of June 16, 2016 and, based on the MPSC Notice and subsequent July 25, 2016 Order 7500 of like effect from the MPSC, we discontinued further negotiations with PNWS.

On August 30, 2016, PNWS sent us a letter demanding that we enter into power purchase agreements for 21 solar projects and threatening to sue us for $106 million if we did not accede to its demand. We declined to do so, and on November 16, 2016, PNWS sued us in state court seeking unspecified damages for breach of contract and other relief, including a judicial declaration that some or all of the proposed power purchase agreements were in effect. We removed the state lawsuit to the United States District Court for the District of Montana, which then stayed the case until September 29, 2017, so that the MPSC could consider related issues that might bear on the issues raised in PNWS's lawsuit.

On July 19, 2017, we and PNWS entered into a partial settlement agreement that resolved some but not all of PNWS' litigation claims. In return for our support of PNWS' application to the MPSC for approval of its first four solar projects, PNWS agreed to drop its damage claims related to the other 17 projects. If the MPSC approves the four projects, PNWS will also drop its damage claims related to those four projects. If the MPSC does not approve the four projects, PNWS will be able

to pursue all of its claims related to those four projects. PNWS can continue to seek (and we can continue to oppose) regulatory approval of the remaining projects, but PNWS will not pursue monetary damage claims related to those projects.

We dispute all of the claims that PNWS has made in its lawsuit and intend to vigorously defend those that have not been resolved by the partial settlement. This matter is in the initial stages, and we cannot predict an outcome or estimate the amount or range of loss that would be associated with an adverse result on the remaining claims.

State of Montana - Riverbed Rents

On April 1, 2016, the State of Montana filed a complaint on remand with the Montana First Judicial District Court (State District Court), naming us, along with Talen, ~~Montana, LLC (Talen),~~ as defendants. The State claims it owns the riverbeds underlying 10 of our hydroelectric facilities (dams, along with reservoirs and tailraces) on the Missouri, Madison and Clark Fork Rivers, and seeks rents for Talen’s and our use and occupancy of such lands. The facilities at issue in the litigation include the Hebgen, Madison, Hauser, Holter, Black Eagle, Rainbow, Cochrane, Ryan and Morony facilities on the Missouri-Madison Rivers and the Thompson Falls facility on the Clark Fork River. We acquired these facilities from Talen in November 2014.

Prior to our acquisition of the facilities, Talen litigated this issue against the State in State District Court, the Montana ~~state courts~~Supreme Court and in the United States Supreme Court. In August 2007, the State District Court determined that the 10 hydroelectric facilities were located on rivers which were navigable and that the State held title to the riverbeds. Subsequently, in June 2008, the State District Court awarded the State compensation with respect to all 10 facilities of approximately $34 million for the 2000-2006 period and approximately $6 million for ~~2007 (we have owned the facilities since November 2014).~~2007. The District Court deferred the determination of compensation for 2008 and future years to the Montana State Land Board.

Talen appealed the issue of navigability to the Montana Supreme Court, which in March 2010 affirmed the State District Court decision. In June 2011, ~~Talen petitioned~~ the United States Supreme Court granted Talen's petition to review the Montana Supreme Court decision. The United States Supreme Court issued an opinion in February 2012, overturning the Montana Supreme Court and holding that the Montana courts erred first by not considering the navigability of the rivers on a segment-by-segment basis and second in relying on present day recreational use of the rivers. The United States Supreme Court also considered the navigability of what it referred to as the Great Falls Reach and concluded, at least from the head of the first waterfall to the foot of the last, that the Great Falls Reach was not navigable for title purposes, and thus the State did not own the riverbeds in that segment. The United States Supreme Court remanded the case to the Montana Supreme Court for further proceedings not inconsistent with its opinion.

Following the 2012 remand, the case laid dormant for four years until the State filed ~~the~~its complaint on remand with the State District Court. The complaint on remand renews all of the State’s claims that the rivers on which the 10 hydroelectric facilities are located are navigable (including the Great Falls Reach), ~~and~~ that because they were navigable the riverbeds became State lands upon Montana’s statehood in 1889 and that the State is entitled to rent for their use. The State’s complaint on remand does not claim any specific rental amount. Pursuant to the terms of our acquisition of the hydroelectric facilities, Talen and NorthWestern will share jointly the expense of this litigation, and Talen is responsible for any rents applicable to the periods of time prior to the acquisition (i.e., before November 18, 2014), while we are responsible for periods thereafter.

InOn April 20, 2016, we removed the case from State District Court to the ~~U.S.~~United States District Court for the District of Montana (Federal District Court), and Talen consented to ~~such~~our removal. ~~In addition,~~On April 27, 2016, we and Talen filed motions with the Federal District Court seeking to dismiss the portion of the litigation dealing with the Great Falls Reach in light of the ~~U.S.~~United States Supreme Court’s decision that the Great Falls Reach was not navigable for title purposes, and thus the State did not own the riverbeds in that segment.

InOn May 19, 2016, the State asked the Federal District Court to remand the case back to the State District Court and to dismiss Talen’s consent to removal. WeThe parties briefed the remand issue and oral argument was held before the Magistrate on January 17, 2017. On January 23, 2017 the Magistrate issued his Findings and Recommendation. The Magistrate recommended the Federal District Court remand the case to State District Court. On February 20, 2017, we filed ~~a brief in opposition~~objections to the ~~State’s motion to remand,~~Magistrate’s Findings and Recommendation, arguing that the Federal District Court should retain jurisdiction. The following day Talen filed ~~a joinder~~its objections to ~~our brief,~~the Federal Magistrate’s Findings and Recommendation, which we joined in on February 23, 2017. On March 21, 2017, the State filed its response to the objections. On March 24, 2017, in separate motions, both we and Talen filed ~~oppositions~~motions asking the Federal District Court to hear oral argument on our respective objections. On July 10, 2017, the Federal District Court granted the motions for oral argument. Oral argument will be held before the U.S. District Judge on August 16, 2017. Our objections to the ~~State’s motion~~Magistrate's Findings and Recommendation along with Talen's and our motions to dismiss ~~Talen’s consent~~the State's claim regarding the Great Falls Reach remain pending. The Federal District Court will not address the motions to ~~removal. The State filed its replies in July~~

~~2016. Following~~dismiss unless it retains jurisdiction. If the ~~State's replies,~~case is remanded to State District Court, we ~~filed a request for oral argument and/or surreply. All of~~will file new motions to dismiss regarding the ~~motions (ours and the State’s) and our request remain pending before the Federal District Court.~~Great Falls Reach.

We dispute the State’s claims and intend to vigorously defend the lawsuit. This matter is in the initial stages, and we cannot predict an outcome. If the Federal District Court (or the State District Court if the case is remanded ~~back~~ to it) determines the riverbeds under all 10 of the hydroelectric facilities are navigable (including the five hydroelectric facilities on the Great Falls Reach) and if it calculates damages as ~~before remand,~~the State District Court did in 2008, we estimate the annual rents could be approximately $7.0 million commencing in November 2014, when we acquired the facilities. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery.

Other Legal Proceedings

We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.


ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS



OVERVIEW

NorthWestern Corporation, doing business as Northwestern Energy, provides electricity and natural gas to approximately ~~701,000~~709,600 customers in Montana, South Dakota and Nebraska. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, ~~2015.~~2016.

As you read this discussion and analysis, refer to our Condensed Consolidated Statements of Income, which present the results of our operations for ~~2016~~2017 and ~~2015.~~2016.



HOW WE PERFORMED AGAINST OUR SECOND QUARTER ~~2015~~2016 RESULTS

Quarter-over-Quarter Change

Gross Margin by Segment⁽¹⁾

Electric

$20.7M

13.3%

$(12.4)M

(7.0)%

Natural Gas

$(0.4)M

(1.1)%

$0.9M

2.6%

Operating Income

$2.6M

4.3%

$(20.0)M

(31.5)%

Net Income

$4.6M

14.8%

$(13.7)M

(38.6)%

EPS (Diluted)

$0.08

12.3%

$(0.29)

(39.7)%

(1) Non-GAAP financial measure. See "non-GAAP Financial Measure" below.



SIGNIFICANT DEVELOPMENTS IN Q2 ~~2016~~2017



	Ÿ	~~An increase~~A decrease in ~~Net Income~~net income of ~~$4.6~~$13.7 million, primarily due to ~~improved gross margin, driven by~~ the recognition in 2016 of $14.2 million of deferred revenue ~~upon receipt~~as a result of ana MPSC final order ~~and an increase in South Dakota electric rates, and lower income tax expense. These improvements were partially offset by the inclusion of a $20.8 million recovery of environmental related costs~~ in our ~~second quarter of 2015 as a reduction of~~tracker filings, lower retail electric volumes and higher operating ~~costs.~~

	Ÿ	~~Issuance of $60 million of South Dakota First Mortgage Bonds at a fixed interest rate of 2.80% maturing~~expenses in ~~2026, to refinance our 6.05%, $55 million First Mortgage Bonds due 2018.~~2017.

Following is a brief overview of significant items for ~~2016, and a discussion of our strategy and outlook.~~2017.



SIGNIFICANT TRENDS AND REGULATION

Montana Natural Gas General Rate ~~Cases~~Filing

~~General rate cases are necessary to cover the costs of providing safe, reliable service, while contributing to earnings growth and achieving~~In June 2017, we reached a settlement agreement with intervenors in our ~~financial objectives. We evaluate the need for electric and~~ natural gas rate ~~changes~~case. This settlement included an overall increase in ~~each~~delivery services and production charges of approximately $5.7 million, based upon a 6.96 percent rate of return (9.55 percent return on equity, 4.67 percent cost of debt and 53.2 percent debt to rate base). In our ~~jurisdictions annually. We are required to make a~~initial filing ~~by the end of~~in September 2016, we requested an annual increase to ~~address the cost-recovery~~natural gas rates of ~~our~~approximately $10.9 million, with rebuttal testimony filed in April 2017 supporting a revised requested annual increase to rates of approximately $9.4 million. The natural gas production part of this filing includes a request for cost-recovery and permanent inclusion in base rates of fields ~~that~~acquired in August 2012 and December 2013 in northern Montana's Bear Paw Basin. Actual production costs are ~~being collected through the natural gas tracker~~currently recovered in customer rates on an interim ~~basis. In addition,~~basis through our supply tracker.

QF Decision

~~Montana Electric~~Under the PURPA, electric utilities are required, with exceptions, to purchase energy and ~~Natural Gas Tracker Filings~~

~~Electric Tracker -~~ capacity from independent power producers that are QFs. The MPSC held a work session in ~~March 2016 and directed staff~~June 2017 to ~~draft~~discuss our application for approval of a final order in our Consolidated Docket that reflects a disallowance of both replacement power costs from a 2013 outage at Colstrip Unit 4 and portfolio modeling costs. On the same day, in a separate work session, the MPSC directed staff to draft a final order in the 2015 Tracker that approved a stipulation between us and the Montana Consumer Counsel, but disallowed portfolio modeling costs. Based on the March 2016 work session, we recorded a disallowance during the first quarter of 2016 totaling approximately $10.3 million, which included $8.2 million of replacement power costs and $2.1 million of modeling costs.

revised tariff for standard rates for small QFs. In April 2016, we received the final written order in the 2015 Tracker, which was consistent with the work session. We filed a motion for reconsideration of the decision with the MPSC regarding the disallowance of portfolio modeling costs, which was denied. In June 2016, we filed an appeal of the decision in Montana District Court.

~~Based on the final order, the impact of the disallowance during the six months ended June 30, 2016 totals $12.4 million, which includes interest of $2.9 million.~~

In addition, the May 2016 Consolidated Docket final order upheld the March 2016 decision regarding replacement power costs concluding that we were imprudent by failing to (1) mitigate a risk by not investigating outage insurance; (2) investigate alternative recovery mechanisms prior to seeking recovery from customers; and (3) meet our burden of proof because the filing lacked sufficient information demonstrating the prudency of the replacement power costs. We filed a motion for reconsideration of the decision with the MPSC. The matter is fully briefed and awaiting a decision by the MPSC.

~~Electric and Natural Gas Lost Revenue Adjustment Mechanism -~~ ~~In October 2015,~~July 2017, the MPSC issued an order ~~eliminating~~establishing a maximum 10-year contract length with a rate adjustment after the ~~lost revenue adjustment mechanism. This mechanism was established~~first five years, and approving rates that do not include costs associated with the risk of potential future carbon dioxide emissions regulations. We expect this will result in ~~2005 by~~substantially lower rates for these contracts. In this same order, the MPSC ~~as a component of an approved energy efficiency program, by which we recovered on an after-the-fact basis a portion of our fixed costs that would otherwise have been collected in~~indicated they will apply the ~~kWh sales lost due~~10-year contract term to ~~energy efficiency programs through our electric and natural supply tracker. Lost revenues were removed prospectively effective December 1, 2015.~~

~~Based on an October 2013 MPSC order,~~us for ~~the period July 1, 2012 through November 30, 2015, we recognized $7.1 million of lost revenues for each annual~~future electric supply tracker period and deferred the remaining $14.2 million of efficiency efforts collected through the trackers pending final approval of the open tracker filings. As discussed above, during the second quarter of 2016, we received final written orders resolving our prior period open tracker dockets. These orders allowed the recovery of the lost revenues included in each tracker period.

resource transactions. We ~~recognized revenue deferred during the July 2012 - November 2015 periods of $14.2 million in the three months ended June 30, 2016 based on the final orders in our tracker filings.~~

~~Hydro Compliance Filing~~

~~The MPSC order approving our acquisition of the hydro assets provided that customers would~~ have no financial risk related to our temporary ownership of the Kerr facility, with a compliance filing required upon completion of the transfer to the Confederated Salish and Kootenai Tribes (CSKT). We sold any excess system generation, which was primarily due to our temporary ownership of Kerr, in the market and provided revenue credits to our Montana retail customers until the transfer to the CSKT. Therefore, during our temporary ownership a net benefit of approximately $2.7 million was provided to customers and there was no benefit to shareholders. In December 2015, we submitted the required compliance filing to remove Kerr from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In January 2016, the MPSC approved an interim adjustment to our hydro generation rate based on the compliance filing, and opened a separate contested docket requesting additional detail on the adjustment to rates due to the conveyance of Kerr. The MPSC identified additional issues and requested information. A procedural schedule has been established and a hearing is scheduled for September 2016. We expect the MPSC to issue a final order during the fourth quarter of 2016.

~~We expect the reduction in revenues as a result of the conveyance of Kerr to be offset with a corresponding reduction in operating expenses.~~

~~FERC Filing - Dave Gates Generating Station at Mill Creek (DGGS)~~

In May 2016, we received an order from the FERC denying a May 2014 request for rehearing and requiring us to make refunds. The request for rehearing challenged a September 2012 FERC Administrative Law Judge's (ALJ) initial decision regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded that only a portion of these costs should be allocated to FERC jurisdictional customers. We had deferred cumulative revenue of approximately $27.3 million, consistent with the ALJ's initial decision, which was refunded to wholesale and choice customers in June 2016 in accordance with the FERC order.

In June 2016, we filed a petition for review of the FERC's May 2016 order with the U.S. Circuit Court of Appeals for the District of Columbia Circuit. The briefing schedule for this appeal has not been established.

The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. DGGS previously provided only regulation service, which is the basis for the cost allocation in our previous MPSC and FERC filings. With the addition of owned hydro generation in November 2014, we are able to shift the utilization of DGGS to additional alternative uses, optimizing our generation portfolio. In support of our biennial electricity supply resource procurement plan that we filed with the MPSC in March 2016, we conducted a portfolio optimization analysis to evaluate options to use DGGS in combination with other generation resources. This analysis indicates DGGS provides cost-effective products necessary to operate our Montana electricity portfolio, including regulation, load following, peaking services and other ancillary products such as contingency reserves, which should guide future cost recovery. The cost recovery of any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. We do not believe an impairment loss is probable at this time; however, we will continue to evaluate recovery of this asset in the future as facts and circumstances change.

~~Montana Electricity Supply Resource Procurement Plan~~

In March 2016, we submitted our electricity supply resource procurement plan (the Plan) to the MPSC, which is updated and filed every two years. The Plan is meant to provide a road map to our stakeholders, including our customers and regulators regarding how we expect to respond to future supply needs and is subject to review and public comment. While we have acquired a significant ~~amount of~~ generation capacity ~~a significant capacity resource deficit persists. The Plan identifies how to best meet the capacity need~~deficits and ~~includes a set of action plans we expect to implement on a going forward basis.~~negative reserve margins. In addition to ~~meeting~~our responsibility to meet peak ~~needs,~~demand, national reliability standards effective in July 2016 require us to have even greater dispatchable generation capacity available and be capable of increasing or decreasing output to address the ~~intermittent~~irregular nature of intermittent generation such as ~~wind. To~~wind or solar. Our 2016 resource plan identified price and reliability risks to our customers of solely relying upon market purchases to address these needs. We are evaluating the ~~need for more generation capacity,~~impact of this decision and have suspended our competitive solicitation process to determine the ~~analysis indicates adding natural gas-fired generation is the lowest-cost/~~lowest-cost / least-risk approach for addressing ~~customers’ peak demand needs.~~our intermittent capacity and reserve margin needs in Montana.

Montana House Bill 193 / Electric and Natural Gas Tracker Filings

House Bill 193 - In April 2017, the Montana legislature passed HB 193, repealing the statute that provided for mandatory recovery of our prudently incurred electric supply costs effective July 1, 2017. In May 2017, the MPSC issued a NCA initiating a process to develop a replacement electric tracker mechanism. We filed a motion for reconsideration of the May 2017 NCA. On July 7, 2017, the MPSC issued an additional NCA addressing the arguments in our motion for reconsideration and identifying three replacement mechanism alternatives for consideration, and establishing a timeline. Two of the replacement mechanism alternatives identified include updating the fixed rate portion of the recovery of our electric supply assets in addition to the variable costs that were recovered through the prior electric tracker. This would be accomplished through an electric supply revenue requirements filing to be made by us by September 30, 2017. The July 2017 NCA also raises questions regarding our earnings as compared with our authorized rate of return for 2016 for electric supply. As noted below in the hydro compliance filing discussion, our 2016 MPSC annual report indicates we earned less than our authorized rate of return with electric delivery service and supply combined. The NCA established a timeline for the parties to provide comments in July 2017, on the issue of whether the MPSC should require a September 2017 filing, and we are ~~evaluating adding incremental generation to our hydro capability as~~awaiting a ~~zero carbon alternative.~~further decision.

~~Supply Investments~~On July 14, 2017, we filed a proposed electric PCCAM with the MPSC. We believe the PCCAM filing is consistent with the MPSC's advocacy for HB 193, the MPSC's May and July 2017 NCAs and the MDU Montana adjustment mechanism that allows for recovery of 90 percent of the increases or decreases in fuel and purchased energy costs from an established baseline. However, we cannot guarantee how the MPSC may apply the statute in establishing a revised mechanism. We expect application of the new mechanism to variable costs to be retroactive to the effective date of HB 193.

We updated our capital spending forecast during the first quarter of 2016 to reflect the Montana procurement plan and our analysis of needs in South Dakota. This included incremental investment of approximately $122 million on internal combustion facilities in Montana, and approximately $65 million of peaking facilities in South Dakota over the five year period that was not included in the forecast in our most recent Form 10-K. Prior to any generation investment we will work with our regulators to define a clear regulatory recovery approach.



RESULTS OF OPERATIONS

Our consolidated results include the results of our reportable business segments, which are primarily engaged in the electric and natural gas business. The overall consolidated discussion is followed by a detailed discussion of gross margin by segment.

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Gross Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross Margin (Revenues less Cost of Sales) is a non-GAAP financial measure due to the exclusion of depreciation and depletion from the measure. The presentation of Gross Margin is intended to supplement investors’ understanding of our operating performance. Gross Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating costs. Our Gross Margin measure may not be comparable to other companies’ Gross Margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

Factors Affecting Results of Operations

Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.

Revenues are also impacted to a lesser extent by customer growth and usage, the latter of which is primarily affected by weather. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.

OVERALL CONSOLIDATED RESULTS

Three Months Ended June 30, ~~2016~~2017 Compared with the Three Months Ended June 30, ~~2015~~2016


	Three Months Ended June 30,									Three Months Ended June 30,
	2016		2015		Change			% Change		2017		2016		Change			% Change
	(dollars in millions)									(dollars in millions)
Operating Revenues
Electric	$	248.4	$	221.4	$	27.0		12.2	%	$	233.9	$	248.4	$	(14.5	)	(5.8	)%
Natural Gas	44.7		49.2		(4.5		)	(9.1	)	50.0		44.7		5.3			11.9
Total Operating Revenues	$	293.1	$	270.6	$	22.5		8.3	%	$	283.9	$	293.1	$	(9.2	)	(3.1	)%


	Three Months Ended June 30,									Three Months Ended June 30,
	2016		2015		Change			% Change		2017		2016		Change			% Change
	(dollars in millions)									(dollars in millions)
Cost of Sales
Electric	$	72.2	$	65.9	$	6.3		9.6	%	$	70.1	$	72.2	$	(2.1	)	(2.9	)%
Natural Gas	9.5		13.6		(4.1		)	(30.1	)	13.9		9.5		4.4			46.3
Total Cost of Sales	$	81.7	$	79.5	$	2.2		2.8	%	$	84.0	$	81.7	$	2.3		2.8	%


	Three Months Ended June 30,									Three Months Ended June 30,
	2016		2015		Change			% Change		2017		2016		Change			% Change
	(dollars in millions)									(dollars in millions)
Gross Margin
Electric	$	176.2	$	155.5	$	20.7		13.3	%	$	163.8	$	176.2	$	(12.4	)	(7.0	)%
Natural Gas	35.2		35.6		(0.4		)	(1.1	)	36.1		35.2		0.9			2.6
Total Gross Margin	$	211.4	$	191.1	$	20.3		10.6	%	$	199.9	$	211.4	$	(11.5	)	(5.4	)%

Primary components of the change in gross margin include the following:


	Gross Margin 2016 vs. 2015			Gross Margin 2017 vs. 2016
	(in millions)			(in millions)
Gross Margin Items Impacting Net Income
Lost revenue adjustment mechanism	$	12.6
South Dakota electric rate increase	10.0
Electric QF adjustment	6.1
2016 Lost revenue adjustment mechanism				$	(14.2	)
Electric retail volumes				(1.4		)
MPSC 2016 disallowance (adjustment)				(0.8		)
Natural gas production	0.9			(0.1		)
MPSC disallowance (adjustment)	0.8
Electric retail volumes	0.3
Natural gas retail volumes	(1.3		)	1.3
Electric transmission	(0.7		)	0.4
Electric QF adjustment				0.4
Other	(1.4		)	(0.7		)
Change in Gross Margin Impacting Net Income	27.3			(15.1		)

Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(5.9		)
Production tax credits flowed-through trackers	(2.7		)
Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers				3.2
Gas production gathering fees	(0.6		)	0.4
Property taxes recovered in trackers	2.2
Change in Items Offset Within Net Income	(7.0		)	3.6
Increase in Consolidated Gross Margin	$	20.3
Decrease in Gross Margin				$	(11.5	)

Consolidated gross margin for items impacting net income ~~increased $27.3~~decreased $15.1 million, due to the following:

The ~~recognition~~inclusion in our 2016 results of $14.2 million of deferred revenue as a result of a MPSC final order in our tracker filings ~~which was~~regarding prior period lost revenues;

A decrease in electric retail volumes due primarily to milder spring weather partly offset ~~in part~~ by ~~the elimination of the lost revenue adjustment mechanism decreasing the recovery of our fixed costs by approximately $1.6 million in the second quarter of 2016;~~

~~An increase in South Dakota electric rates;~~

~~The inclusion in our 2015 results of an increase in supply costs due to the adjustment of the QF liability based on a review of contract assumptions;~~

~~An increase in natural gas production revenue due to a change in interim rates based on actual costs;~~customer growth;

An adjustment in 2016 in the disallowance of modeling costs based on ~~the~~an MPSC final ~~order, as discussed above;~~order; and

~~An increase in electric residential and commercial volumes~~Lower gas production margin due primarily to ~~customer growth. Warmer spring weather~~a $0.4 million reduction in ~~South Dakota was~~interim rates of the production assets recovered through the natural gas tracker, partly offset by ~~unfavorable weather~~a $0.3 million increase in ~~Montana.~~ overhead fees.

These ~~increases~~decreases were partly offset byby:

~~A decrease~~

An increase in natural gas retail volumes due primarily to ~~warmer~~colder spring weather ~~partly offset by~~in our Montana and South Dakota jurisdictions and customer growth; ~~and~~

~~Lower~~Higher demand to transmit energy across our transmission lines due to market conditions and pricing; and

A decrease in QF related supply costs based on actual QF pricing and ~~other conditions.~~output.

The change in consolidated gross margin also includes the following items that had no impact on net income:

~~A decrease in revenues from the conveyance of the Kerr facility to the CSKT in September 2015 (offset by reduced operating expenses);~~

~~A decrease in revenues for production tax credits associated with the Beethoven wind project, which is a reduction in our customers rates (offset by reduced income tax expense);~~

~~A decrease in natural gas gathering fees (offset by reduced operating expenses); and~~

An increase in revenues for property taxes included in trackers ~~(offset~~is offset by increased property tax ~~expense).~~expense with no impact to net income; and

An increase in natural gas production gathering fees is offset by an increase in operating expenses.


	Three Months Ended June 30,								Three Months Ended June 30,
	2016		2015		Change		% Change		2017		2016		Change		% Change
	(dollars in millions)								(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	72.6	$	61.7	$	10.9	17.7	%	$	75.2	$	72.6	$	2.6	3.6	%
Property and other taxes	35.2		32.5		2.7		8.3		39.5		35.2		4.3		12.2
Depreciation and depletion	39.9		35.7		4.2		11.8		41.5		39.9		1.6		4.0
	$	147.7	$	129.9	$	17.8	13.7	%	$	156.2	$	147.7	$	8.5	5.8	%

Consolidated operating, general and administrative expenses were $75.2 million for the three months ended June 30, 2017, as compared with $72.6 million for the three months ended June 30, ~~2016, as compared with $61.7 million for the three months ended June 30, 2015.~~2016. Primary components of the change include the following:


	Operating, General & Administrative Expenses			Operating, General & Administrative Expenses
	2016 vs. 2015			2017 vs. 2016
	(in millions)			(in millions)
Insurance recovery, net	$	20.8
Labor				$	0.9
Bad debt expense				0.6
Maintenance costs				0.5
Non-employee directors deferred compensation	1.6			0.4
Hydro operations - Kerr conveyance	(5.6		)
Distribution System Infrastructure Project (DSIP) expenses	(1.3		)
Bad debt expense	(1.2		)
Gas production gathering expense	(0.6		)
Natural gas production gathering expense				0.4
Other	(2.8		)	(0.2		)
Increase in Operating, General & Administrative Expenses	$	10.9		$	2.6

The increase in operating, general and administrative expenses is primarily due to the following:

~~The inclusion in~~Increased labor costs due primarily to compensation increases and more time spent by employees on maintenance projects (which are expensed) rather than capital projects;

Higher bad debt expense;

Higher maintenance costs at our ~~second quarter 2015 results of an insurance recovery, primarily associated with electric generation related environmental remediation costs incurred in prior periods;~~Dave Gates Generating Station and Colstrip Unit 4;

The change in value of non-employee directors deferred compensation due to changes in our stock price (offset by changes in other income with no impact on net income).; and

~~These increases were offset in part by:~~

~~A decrease in hydro operations costs in the current period is a result of the conveyance of Kerr to the CSKT in September 2015 (offset by reduced revenue discussed above);~~

~~Lower DSIP related expenses;~~

~~Lower bad debt expense, due to improved collection of receivables from customers;~~

~~A decrease~~An increase in natural gas production gathering expense (offset by ~~lower~~higher gathering fees discussed above)~~; and~~

~~Cost control measures implemented in 2016, which are included in Other.~~.

Property and other taxes were ~~$35.2~~$39.5 million for the three months ended June 30, ~~2016,~~2017, as compared with ~~$32.5~~$35.2 million in the same period of ~~2015.~~2016. This increase was primarily due to plant additions and higher estimated property valuations in ~~Montana, offset in part by a $0.3 million decrease from the conveyance of Kerr to the CSKT in September 2015.~~Montana. We estimate property taxes throughout each year, and update tobased on valuation reports received from the ~~actual expense when we receive our~~ Montana ~~property tax bills in November. In addition, under~~Department of Revenue. Under Montana law, we are allowed to track the increases in the actual level of state and local taxes and fees and recover these amounts. ~~The MPSC has authorized~~Our Montana property tax tracker mechanism currently allows for the recovery of

approximately 60% of the estimated increase in our state and local taxes and fees (primarily property taxes) as compared towith the related amount included in rates during our last general rate case.

Depreciation and depletion expense was ~~$39.9~~$41.5 million for the three months ended June 30, ~~2016,~~2017, as compared with ~~$35.7~~$39.9 million in the same period of ~~2015.~~2016. This increase was primarily due to plant ~~additions, including approximately $1.4 million of depreciation associated with the Beethoven wind project acquisition.~~additions.

Consolidated operating income for the three months ended June 30, ~~2016~~2017 was ~~$63.7~~$43.7 million as compared with ~~$61.1~~$63.7 million in the same period of ~~2015.~~2016. This ~~increase~~decrease was primarily due to the ~~increase~~decrease in gross margin ~~offset~~driven by the recognition in ~~part by~~2016 of deferred revenue as a result of a MPSC final order, lower electric retail volumes and higher ~~operating costs as discussed above.~~property taxes.

Consolidated interest expense for the three months ended June 30, ~~2016~~2017 was ~~$26.4~~$23.4 million, as compared with ~~$22.9~~$26.4 million in the same period of ~~2015.~~2016. This ~~increase~~decrease was primarily due to $2.9 million of interest associated with the 2016 MPSC

disallowance ~~as discussed above, increased debt outstanding associated~~along with the ~~September 2015 Beethoven wind project acquisition, and lower capitalization~~debt refinancing of ~~allowance for funds used~~the Pollution Control Revenue Refunding Bonds during ~~construction (AFUDC).~~the third quarter of 2016.

Consolidated other income for the three months ended June 30, ~~2016,~~2017, was ~~$1.2~~$2.1 million, as compared with ~~$1.0~~$1.2 million in the same period of ~~2015.~~2016. This increase was primarily due to higher capitalization of allowance for funds used during construction (AFUDC) and a ~~$1.6~~$0.4 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation (which, as discussed above, is offset by a corresponding ~~increase~~decrease to operating, general and administrative expenses). ~~This is partially offset by lower capitalization of AFUDC.~~

Consolidated income tax expense for the three months ended June 30, ~~2016~~2017 was ~~$2.9~~$0.6 million, as compared with ~~$8.2~~$2.9 million in the same period of ~~2015.~~2016. Our effective tax rate for the three months ended June 30, ~~2016~~2017 was ~~7.7%~~2.6% as compared with ~~21.0%~~7.7% for the same period of ~~2015.~~2016. We ~~currently~~ expect our ~~2016~~2017 effective tax rate to range between 6%7% - ~~10%~~11%.

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):


	Three Months Ended June 30,										Three Months Ended June 30,
	2016					2015					2017					2016
Income Before Income Taxes	$	38.5				$	39.2				$	22.4				$	38.5

Income tax calculated at 35% federal statutory rate	13.5			35.0	%	13.7			35.0	%	7.8			35.0	%	13.5			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(1.0		)	(2.7	)	0.4			0.9		(0.5		)	(2.2	)	(1.0		)	(2.7	)
Flow-through repairs deductions	(7.0		)	(18.1	)	(4.9		)	(12.4	)	(4.7		)	(21.2	)	(7.0		)	(18.1	)
Production tax credits	(2.3		)	(6.0	)	(0.7		)	(1.7	)	(1.4		)	(6.5	)	(2.3		)	(6.0	)
Plant and depreciation of flow through items	(0.3		)	(0.6	)	(0.2		)	(0.6	)	(0.7		)	(3.1	)	(0.3		)	(0.6	)
Prior year permanent return to accrual adjustments	(0.1		)	(0.3	)	—			—		—			—		(0.1		)	(0.3	)
Other, net	0.1			0.4		(0.1		)	(0.2	)	0.1			0.6		0.1			0.4
	(10.6		)	(27.3	)	(5.5		)	(14.0	)	(7.2		)	(32.4	)	(10.6		)	(27.3	)

Income Tax Expense	$	2.9		7.7	%	$	8.2		21.0	%	$	0.6		2.6	%	$	2.9		7.7	%

We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits.

Consolidated net income for the three months ended June 30, ~~2016~~2017 was ~~$35.6~~$21.8 million as compared with ~~$31.0~~$35.6 million for the same period in ~~2015.~~2016. This ~~increase~~decrease was primarily due to ~~improved gross margin, due to~~ the recognition in 2016 of deferred revenue as a result of a MPSC final order in our tracker filings, lower electric retail volumes and ~~the South Dakota electric rate increase, and lower income tax expense,~~higher operating expenses as discussed above, partly offset by ~~higher operating expenses due to the insurance recovery included in our 2015 results~~lower interest and ~~higher interest~~income tax expense.

Six Months Ended June 30, ~~2016~~2017 Compared with the Six Months Ended June 30, ~~2015~~2016


	Six Months Ended June 30,									Six Months Ended June 30,
	2016		2015		Change			% Change		2017		2016		Change		% Change
	(dollars in millions)									(dollars in millions)
Operating Revenues
Electric	$	489.7	$	457.4	$	32.3		7.1	%	$	500.1	$	489.7	$	10.4	2.1	%
Natural Gas	135.9		159.2		(23.3		)	(14.6	)	151.1		135.9		15.2		11.2
Total Operating Revenues	$	625.6	$	616.6	$	9.0		1.5	%	$	651.2	$	625.6	$	25.6	4.1	%


	Six Months Ended June 30,									Six Months Ended June 30,
	2016		2015		Change			% Change		2017		2016		Change			% Change
	(dollars in millions)									(dollars in millions)
Cost of Sales
Electric	$	155.8	$	129.8	$	26.0		20.0	%	$	155.5	$	155.8	$	(0.3	)	(0.2	)%
Natural Gas	41.3		62.1		(20.8		)	(33.5	)	48.3		41.3		7.0			16.9
Total Cost of Sales	$	197.1	$	191.9	$	5.2		2.7	%	$	203.8	$	197.1	$	6.7		3.4	%


	Six Months Ended June 30,									Six Months Ended June 30,
	2016		2015		Change			% Change		2017		2016		Change		% Change
	(dollars in millions)									(dollars in millions)
Gross Margin
Electric	$	333.9	$	327.6	$	6.3		1.9	%	$	344.6	$	333.9	$	10.7	3.2	%
Natural Gas	94.6		97.1		(2.5		)	(2.6	)	102.8		94.6		8.2		8.7
Total Gross Margin	$	428.5	$	424.7	$	3.8		0.9	%	$	447.4	$	428.5	$	18.9	4.4	%

Primary components of the change in gross margin include the following:


	Gross Margin 2016 vs. 2015			Gross Margin 2017 vs. 2016
	(in millions)			(in millions)
Gross Margin Items Impacting Net Income
MPSC 2016 disallowance				$	9.5
Natural gas retail volumes				7.3
Electric retail volumes				7.2
South Dakota electric rate increase	$	18.6		1.2
Lost revenue adjustment mechanism	10.6
Electric QF adjustment	6.1			0.4
MPSC disallowance	(9.5		)
Electric transmission	(2.0		)	0.2
Natural gas retail volumes	(1.1		)
2016 Lost revenue adjustment mechanism				(14.2		)
Natural gas production	(0.7		)	(0.7		)
Electric retail volumes	(0.7		)
Other	(2.7		)	1.3
Change in Gross Margin Impacting Net Income	18.6			12.2

Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(11.8		)
Production tax credits flowed-through trackers	(5.9		)
Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers				6.3
Gas production gathering fees	(1.0		)	0.4
Property taxes recovered in trackers	3.9
Change in Items Offset Within Net Income	(14.8		)	6.7
Increase in Consolidated Gross Margin	$	3.8
Increase in Gross Margin				$	18.9

Consolidated gross margin for items impacting net income increased ~~$18.6~~$12.2 million, ~~which includes~~due to the following:

The inclusion in our 2016 results of the MPSC disallowance of both replacement power costs from a 2013 outage at Colstrip Unit 4 and portfolio modeling costs;

An increase in natural gas retail volumes due primarily to colder winter and spring weather and customer growth;

An increase in electric retail volumes due primarily to colder winter weather and customer growth, partly offset by milder spring weather;

An increase in South Dakota electric ~~rates;~~revenue due to the timing of the change in customer rates in 2016;

A decrease in QF related supply costs based on actual QF pricing and output; and

Higher demand to transmit energy across our transmission lines due to market conditions and pricing.

These increases were partly offset by:

The ~~recognition~~inclusion in our 2016 results of $14.2 million of deferred revenue as a result of a MPSC final order in our tracker filings ~~offset in part by the elimination of the~~regarding prior period lost ~~revenue adjustment mechanism decreasing the recovery of our fixed costs by approximately $3.6 million in 2016;~~revenues; and

~~The inclusion in our 2015 results of an increase in supply costs due to the adjustment of the QF liability based on a review of contract assumptions. These increases were partly offset by~~

~~The MPSC disallowance of previously incurred costs as discussed above;~~

Lower ~~demand to transmit energy across our transmission lines due to market pricing and other conditions;~~

~~A decrease in natural gas volumes due primarily to warmer spring weather, partly offset by customer growth;~~

~~A decrease in natural~~ gas production margin due primarily to ~~a change~~$1.0 million reduction in interim rates ~~based on actual costs; and~~

~~A decrease in electric retail volumes due primarily to warmer winter weather and lower industrial volumes~~ of ~~a large Montana customer,~~production assets recovered through the natural gas tracker, partly offset by ~~customer growth.~~a $0.3 million increase in overhead fees.

The change in consolidated gross margin also includes the following items that had no impact on net income:

~~A decrease in revenues from the conveyance of the Kerr facility to the CSKT in September 2015 (offset by reduced operating expenses);~~

~~A decrease in revenues for production tax credits associated with the Beethoven wind project, which is a reduction in our customers rates (offset by reduced income tax expense);~~

~~A decrease in natural gas gathering fees (offset by reduced operating expenses); and~~

An increase in revenues for property taxes included in trackers ~~(offset~~is offset by increased property tax ~~expense).~~expense with no impact to net income; and

An increase in natural gas production gathering fees is offset by an increase in operating expenses.


	Six Months Ended June 30,								Six Months Ended June 30,
	2016		2015		Change		% Change		2017		2016		Change		% Change
	(dollars in millions)								(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	152.4	$	142.8	$	9.6	6.7	%	$	156.2	$	152.4	$	3.8	2.5	%
Property and other taxes	70.6		65.2		5.4		8.3		79.4		70.6		8.8		12.5
Depreciation and depletion	79.8		71.6		8.2		11.5		83.0		79.8		3.2		4.0
	$	302.8	$	279.6	$	23.2	8.3	%	$	318.6	$	302.8	$	15.8	5.2	%

Consolidated operating, general and administrative expenses were $156.2 million for the six months ended June 30, 2017, as compared with $152.4 million for the six months ended June 30, ~~2016, as compared with $142.8 million for the six months ended June 30, 2015.~~2016. Primary components of the change include the following:


	Operating, General & Administrative Expenses			Operating, General & Administrative Expenses
	2016 vs. 2015			2017 vs. 2016
	(in millions)			(in millions)
Insurance recovery, net	$	20.8
Maintenance costs				$	2.0
Bad debt expense				1.9
Labor				1.4
Natural gas production gathering expense				0.4
Non-employee directors deferred compensation	4.7			(1.3		)
Insurance reserves	0.9			(1.0		)
Hydro operations - Kerr conveyance	(11.2		)
Bad debt expense	(2.2		)
DSIP expenses	(1.6		)
Gathering expense	(1.0		)
Other	(0.8		)	0.4
Increase in Operating, General & Administrative Expenses	$	9.6		$	3.8

The increase in operating, general and administrative expenses is primarily due to the following:

~~The inclusion~~Higher maintenance costs at our Dave Gates Generating Station and Colstrip Unit 4;

Higher bad debt expense due to an increase in ~~our second quarter 2015 results~~revenues as a result of ~~an insurance recovery,~~colder weather;

Increased labor costs due primarily ~~associated with electric generation related environmental remediation costs incurred~~to compensation increases and more time spent by employees on maintenance projects (which are expensed) rather than capital projects; and

An increase in ~~prior periods;~~natural gas production gathering expense (offset by higher gathering fees discussed above).

These increases were offset in part by:

The change in value of non-employee directors deferred compensation due to changes in our stock price (offset by changes in other income with no impact on net income); and

~~An increase~~A decrease in insurance reserves primarily due to the amount recorded in 2016 related to the Billings, Montana refinery ~~outage discussed in Note 13 to the Financial Statements.~~

~~These increases were offset in part by:~~

~~A decrease in hydro operations costs in the current period as a result of the conveyance of Kerr to the CSKT in September 2015 (offset by reduced revenue discussed above);~~

~~Lower bad debt expense, due to improved collection of receivables from customers;~~

~~Lower DSIP related expenses;~~

~~A decrease in natural gas gathering expense (offset by lower gathering fees discussed above); and~~

~~Cost control measures implemented in 2016, which are included in Other.~~outage.

Property and other taxes were ~~$70.6~~$79.4 million for the six months ended June 30, ~~2016,~~2017, as compared with ~~$65.2~~$70.6 million in the same period of ~~2015.~~2016. This increase was primarily due to plant additions and higher estimated property valuations in ~~Montana, offset~~Montana. We expect property tax expense to increase by approximately $10 million on an annual basis in ~~part by a $0.6 million decrease from the conveyance of Kerr to the CSKT in September 2015.~~2017 as compared with 2016.

Depreciation and depletion expense was ~~$79.8~~$83.0 million for the six months ended June 30, ~~2016,~~2017, as compared with ~~$71.6~~$79.8 million in the same period of ~~2015.~~2016. This increase was primarily due to plant ~~additions, including approximately $2.8 million of depreciation associated with the September 2015 Beethoven wind project acquisition.~~

additions.

Consolidated operating income for the six months ended June 30, ~~2016~~2017 was ~~$125.7~~$128.8 million as compared with ~~$145.0~~$125.7 million in the same period of ~~2015.~~2016. This ~~decrease~~increase was primarily due to the ~~$20.8 million insurance recovery~~increase in ~~2015, partly offset by higher~~ gross margin as discussed ~~above.~~above, offset in part by higher operating expenses.

Consolidated interest expense for the six months ended June 30, ~~2016~~2017 was ~~$50.9~~$46.8 million, as compared with ~~$46.1~~$50.9 million in the same period of ~~2015.~~2016. This ~~increase~~decrease was primarily due to $2.9 million of interest associated with the 2016 MPSC disallowance as discussed above ~~increased debt outstanding associated~~along with the ~~Beethoven wind project acquisition, and lower capitalization~~debt refinancing of ~~allowance for funds used~~the Pollution Control Revenue Refunding Bonds during ~~construction (AFUDC).~~the third quarter of 2016.

Consolidated other income for the six months ended June 30, ~~2016,~~2017, was ~~$4.3~~$3.6 million, as compared with ~~$1.7~~$4.3 million in the same period of ~~2015.~~2016. This ~~increase~~decrease was primarily due to a ~~$4.7~~$1.3 million ~~increase~~decrease in the value of deferred shares held in trust for non-employee directors deferred compensation (which, as discussed above, is offset by a corresponding ~~increase~~decrease to operating, general and administrative expenses). This decrease was ~~partially~~ offset in part by ~~lower~~higher capitalization of AFUDC.

Consolidated income tax expense for the six months ended June 30, ~~2016~~2017 was ~~$5.4~~$7.3 million, as compared with ~~$18.2~~$3.6 million in the same period of ~~2015.~~2016. Our effective tax rate for the six months ended June 30, ~~2016~~2017 was ~~6.9%~~8.5% as compared with ~~18.1%~~4.6% for the same period of ~~2015.~~2016. We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016, which resulted in the recognition of $1.8 million in excess tax benefits. In accordance with the guidance, the $1.8 million impact of this adoption is reflected as of January 1, 2016, which reduced tax expense for the six months ended June 30, 2016.

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):


	Six Months Ended June 30,										Six Months Ended June 30,
	2016					2015					2017					2016
Income Before Income Taxes	$	79.0				$	100.6				$	85.7				$	79.0

Income tax calculated at 35% federal statutory rate	27.7			35.0	%	35.2			35.0	%	30.0			35.0	%	27.7			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(2.1		)	(2.6	)	0.5			0.6		(1.3		)	(1.5	)	(2.3		)	(2.9	)
Flow-through repairs deductions	(13.7		)	(17.3	)	(14.5		)	(14.4	)	(13.6		)	(15.8	)	(13.7		)	(17.3	)
Production tax credits	(5.1		)	(6.5	)	(1.9		)	(1.9	)	(5.3		)	(6.2	)	(5.1		)	(6.5	)
Plant and depreciation of flow through items	(1.2		)	(1.5	)	(0.6		)	(0.6	)	(2.1		)	(2.5	)	(1.2		)	(1.5	)
Share-based compensation											(0.4		)	(0.5	)	(1.6		)	(2.1	)
Prior year permanent return to accrual adjustments	(0.1		)	(0.2	)	—			—		—			—		(0.1		)	(0.1	)
Other, net	(0.1		)	—		(0.5		)	(0.6	)	—			—		(0.1		)	—
	(22.3		)	(28.1	)	(17.0		)	(16.9	)	(22.7		)	(26.5	)	(24.1		)	(30.4	)

Income Tax Expense	$	5.4		6.9	%	$	18.2		18.1	%	$	7.3		8.5	%	$	3.6		4.6	%

Consolidated net income for the six months ended June 30, ~~2016~~2017 was ~~$73.6~~$78.4 million as compared with ~~$82.4~~$75.4 million for the same period in ~~2015.~~2016. This ~~decrease~~increase was primarily due to ~~the inclusion in our 2015 results~~improved gross margin as a result of ~~a $20.8 million insurance recovery~~favorable weather and ~~higher~~lower interest expense, partly offset by higher ~~other income~~operating and ~~lower~~ income tax expense.

ELECTRIC SEGMENT

We have various classifications of electric revenues, defined as follows:

Retail: Sales of electricity to residential, commercial and industrial customers.

Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers.

Transmission: Reflects transmission revenues regulated by the FERC.

Ancillary Services: FERC jurisdictional services that ensure reliability and support the transmission of electricity from generation sites to customer loads. Such services include regulation service, reserves and voltage support.

Wholesale and other: ~~In October 2015, we became~~Our South Dakota service territory is a ~~member of~~market participant in the Southwest Power Pool, ~~(SPP), which is a regional transmission organization. As a market participant in SPP,~~where we buy and sell wholesale energy and reserves through the operation of a single, consolidated ~~SPP~~ balancing authority. ~~As such, the increase in wholesale revenues is offset through an increase in cost of sales.~~ This line also includes miscellaneous electric revenues.

Three Months Ended June 30, ~~2016~~2017 Compared with the Three Months Ended June 30, ~~2015~~2016


	Results									Results
	2016		2015		Change			% Change		2017		2016		Change			% Change
	(dollars in millions)									(dollars in millions)
Retail revenues	$	200.6	$	193.7	$	6.9		3.6	%	$	196.0	$	200.6	$	(4.6	)	(2.3	)%
Regulatory amortization	16.1		11.6		4.5			38.8		4.5		16.1		(11.6		)	(72.0	)
Total retail revenues	216.7		205.3		11.4			5.6		200.5		216.7		(16.2		)	(7.5	)
Transmission	12.7		13.4		(0.7		)	(5.2	)	13.1		12.7		0.4			3.1
Ancillary services	0.4		0.4		—			—		0.4		0.4		—			—
Wholesale and other	18.6		2.3		16.3			708.7		19.9		18.6		1.3			7.0
Total Revenues	248.4		221.4		27.0			12.2		233.9		248.4		(14.5		)	(5.8	)
Total Cost of Sales	72.2		65.9		6.3			9.6		70.1		72.2		(2.1		)	(2.9	)
Gross Margin	$	176.2	$	155.5	$	20.7		13.3	%	$	163.8	$	176.2	$	(12.4	)	(7.0	)%


	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts		Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2016		2015		2016	2015	2016	2015	2017		2016		2017	2016	2017	2016
	(in thousands)								(in thousands)
Montana	$	63,044	$	61,261	522	506	290,743	286,903	$	59,740	$	63,044	503	522	294,721	290,743
South Dakota	12,640		9,933		113	108	49,946	49,739	12,832		12,640		110	113	50,158	49,946
Residential	75,684		71,194		635	614	340,689	336,642	72,572		75,684		613	635	344,879	340,689
Montana	85,611		85,586		775	780	65,421	64,539	83,028		85,611		764	775	66,277	65,421
South Dakota	20,706		16,836		231	224	12,642	12,508	21,400		20,706		230	231	12,687	12,642
Commercial	106,317		102,422		1,006	1,004	78,063	77,047	104,428		106,317		994	1,006	78,964	78,063
Industrial	9,772		11,177		538	574	73	75	10,087		9,772		554	538	75	73
Other	8,841		8,899		50	52	6,222	6,230	8,920		8,841		51	50	6,205	6,222
Total Retail Electric	$	200,614	$	193,692	2,229	2,244	425,047	419,994	$	196,007	$	200,614	2,212	2,229	430,123	425,047


	Cooling Degree Days			2016 as compared with:		Cooling Degree Days			2017 as compared with:
	2016	2015	Historic Average	2015	Historic Average	2017	2016	Historic Average	2016	Historic Average
Montana	72	107	43	33% colder	67% warmer	57	89	47	36% colder	21% warmer
South Dakota	98	69	62	42% warmer	58% warmer	91	98	58	7% colder	57% warmer


	Heating Degree Days			2016 as compared with:		Heating Degree Days			2017 as compared with:
	2016	2015	Historic Average	2015	Historic Average	2017	2016	Historic Average	2016	Historic Average
Montana	1,011	1,097	1,282	8% warmer	21% warmer	1,061	973	1,223	9% colder	13% warmer
South Dakota	1,246	1,180	1,474	6% colder	15% warmer	1,321	1,246	1,410	6% colder	6% warmer

The following summarizes the components of the changes in electric gross margin for the three months ended June 30, ~~2016~~2017 and ~~2015~~2016:


	Gross Margin 2016 vs. 2015			Gross Margin 2017 vs. 2016
	(in millions)			(in millions)
Gross Margin Items Impacting Net Income
Lost revenue adjustment mechanism	$	11.8		$	(13.4	)
South Dakota rate increase	10.0
Retail volumes				(1.4		)
MPSC 2016 disallowance (adjustment)				(0.8		)
Transmission				0.4
QF adjustment	6.1			0.4
MPSC disallowance (adjustment)	0.8
Retail volumes	0.3
Transmission	(0.7		)
Other	(0.9		)	(0.5		)
Change in Gross Margin Impacting Net Income	27.4			(15.3		)

Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(5.9		)
Production tax credits flowed-through trackers	(2.7		)
Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers	1.9			2.9
Change in Items Offset Within Net Income	(6.7		)	2.9
Increase in Consolidated Gross Margin	$	20.7
Decrease in Gross Margin				$	(12.4	)

Gross margin for items impacting net income ~~increased $27.4~~decreased $15.3 million including the following:

The recognition in 2016 of $13.4 million of deferred revenue as a result of a MPSC final order in our tracker ~~filings, which was~~filings;

A decrease in electric residential and commercial retail volumes due primarily to milder spring weather partly offset ~~in part~~ by ~~the elimination of the lost revenue adjustment mechanism decreasing the recovery of our fixed costs;~~

~~An increase in South Dakota electric rates;~~

~~The inclusion~~growth in our ~~2015 results of an increase in our QF liability based on a review of contract assumptions;~~residential and industrial customers; and

An adjustment in 2016 in the disallowance of modeling costs based on the MPSC final ~~order, as discussed above; and~~order.

~~An increase in residential and commercial retail volumes, due primarily to customer growth. Warmer spring weather in South Dakota was offset by unfavorable weather in Montana.~~

These ~~increases~~decreases were partly offset byby:

~~Lower~~

Higher demand to transmit energy across our transmission lines due to market ~~pricing~~conditions and ~~other conditions.~~

~~The change in gross margin also includes the following items that had no impact on net income:~~

pricing; and

A decrease in ~~revenues from the conveyance of the Kerr facility to the CSKT in September 2015 (offset by reduced operating expenses);~~QF related supply costs based on actual QF pricing and output.

~~A decrease in revenues for production tax credits associated with the Beethoven wind project, which is a reduction in our customers rates (offset by reduced income tax expense); and~~

AnThe increase in revenues for property taxes included in trackers ~~(offset~~is offset by increased property tax ~~expense).~~expense with no impact to net income.

The change in regulatory amortization revenue ~~is due to~~includes the recognition of deferred revenue in 2016, as discussed above and timing differences between when we incur electric supply costs and when we recover these costs in rates from our ~~customers, which has~~customers. These timing differences have a minimal impact on gross margin. In addition, while

heating and cooling degree days may fluctuate significantly during the second quarter, our electric customer usage is not highly

sensitive to these changes between the heating and cooling seasons. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

Six Months Ended June 30, ~~2016~~2017 Compared with the Six Months Ended June 30, ~~2015~~2016


	Results									Results
	2016		2015		Change			% Change		2017			2016		Change			% Change
	(dollars in millions)									(dollars in millions)
Retail revenues	$	410.8	$	413.7	$	(2.9	)	(0.7	)%	$	430.7		$	410.8	$	19.9		4.8	%
Regulatory amortization	12.7		10.6		2.1			19.8		(0.7		)	12.7		(13.4		)	(105.5	)
Total retail revenues	423.5		424.3		(0.8		)	(0.2	)	430.0			423.5		6.5			1.5
Transmission	25.3		27.3		(2.0		)	(7.3	)	25.5			25.3		0.2			0.8
Ancillary services	0.8		0.8		—			—		0.8			0.8		—			—
Wholesale and other	40.1		5.0		35.1			702.0		43.8			40.1		3.7			9.2
Total Revenues	489.7		457.4		32.3			7.1		500.1			489.7		10.4			2.1
Total Cost of Sales	155.8		129.8		26.0			20.0		155.5			155.8		(0.3		)	(0.2	)
Gross Margin	$	333.9	$	327.6	$	6.3		1.9	%	$	344.6		$	333.9	$	10.7		3.2	%


	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts		Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2016		2015		2016	2015	2016	2015	2017		2016		2017	2016	2017	2016
	(in thousands)								(in thousands)
Montana	$	139,734	$	140,988	1,189	1,172	290,399	286,427	$	150,548	$	139,734	1,264	1,189	294,471	290,399
South Dakota	27,878		24,655		281	292	49,928	49,756	30,168		27,878		289	281	50,167	49,928
Residential	167,612		165,643		1,470	1,464	340,327	336,183	180,716		167,612		1,553	1,470	344,638	340,327
Montana	168,634		175,425		1,568	1,573	65,349	64,454	171,136		168,634		1,579	1,568	66,194	65,349
South Dakota	41,200		35,874		482	481	12,554	12,415	43,810		41,200		485	482	12,616	12,554
Commercial	209,834		211,299		2,050	2,054	77,903	76,869	214,946		209,834		2,064	2,050	78,810	77,903
Industrial	19,690		22,992		1,073	1,140	73	75	20,952		19,690		1,132	1,073	75	73
Other	13,616		13,794		73	76	5,445	5,402	14,057		13,616		74	73	5,443	5,445
Total Retail Electric	$	410,752	$	413,728	4,666	4,734	423,748	418,529	$	430,671	$	410,752	4,823	4,666	428,966	423,748


	Cooling Degree Days			2016 as compared with:		Cooling Degree Days			2017 as compared with:
	2016	2015	Historic Average	2015	Historic Average	2017	2016	Historic Average	2016	Historic Average
Montana	72	107	43	33% colder	67% warmer	57	89	47	36% colder	21% warmer
South Dakota	98	69	62	42% warmer	58% warmer	91	98	58	7% colder	57% warmer


	Heating Degree Days			2016 as compared with:		Heating Degree Days			2017 as compared with:
	2016	2015	Historic Average	2015	Historic Average	2017	2016	Historic Average	2016	Historic Average
Montana	3,998	3,988	4,570	-	13% warmer	4,437	3,852	4,496	15% colder	1% warmer
South Dakota	4,920	5,269	5,548	7% warmer	11% warmer	5,211	4,920	5,535	6% colder	6% warmer

The following summarizes the components of the changes in electric gross margin for the six months ended June 30, ~~2016~~2017 and ~~2015~~2016:


	Gross Margin 2016 vs. 2015			Gross Margin 2017 vs. 2016
	(in millions)			(in millions)
Gross Margin Items Impacting Net Income
MPSC 2016 disallowance				$	9.5
Retail volumes				7.2
South Dakota rate increase	$	18.6		1.2
Lost revenue adjustment mechanism	10.0
QF adjustment	6.1			0.4
MPSC disallowance	(9.5		)
Transmission	(2.0		)	0.2
Retail volumes	(0.7		)
2016 Lost revenue adjustment mechanism				(13.4		)
Other	(1.8		)	0.8
Change in Gross Margin Impacting Net Income	20.7			5.9

Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(11.8		)
Production tax credits flowed-through trackers	(5.9		)
Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers	3.3			4.8
Change in Items Offset Within Net Income	(14.4		)	4.8
Increase in Consolidated Gross Margin	$	6.3
Increase in Gross Margin				$	10.7

~~This increase~~Gross margin for items impacting net income increased $5.9 million including the following:

The inclusion in ~~gross margin was due to the same reasons discussed in the three months ended section above, partially offset by the $9.5 million net impact~~2016 of the MPSC disallowance of ~~previously incurred costs. Retail~~both replacement power costs from a 2013 outage at Colstrip Unit 4 and portfolio modeling costs;

An increase in residential and commercial retail volumes ~~decreased~~due primarily ~~due~~ to ~~warmer~~colder winter weather and ~~lower~~growth in our residential and industrial ~~volumes of a large Montana customer,~~customers, partly offset by milder spring weather;

An increase in South Dakota electric rates due to the timing of the change in customer ~~growth.~~rates in 2016;

A decrease in QF related supply costs based on actual QF pricing and output; and

Higher demand to transmit energy across our transmission lines due to market conditions and pricing.

These increases were partly offset by the recognition in 2016 of $13.4 million of deferred revenue as a result of a MPSC final order in our tracker filings. In addition, the increase in revenues for property taxes included in trackers is offset by increased property tax expense with no impact to net income.

The change in regulatory amortization revenue is primarily due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on gross margin. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

NATURAL GAS SEGMENT

We have various classifications of natural gas revenues, defined as follows:

Retail: Sales of natural gas to residential, commercial and industrial customers.

Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in cost of sales and therefore has minimal impact on gross margin.

Wholesale: Primarily represents transportation and storage for others.

Three Months Ended June 30, ~~2016~~2017 Compared with the Three Months Ended June 30, ~~2015~~2016


	Results									Results
	2016		2015		Change			% Change		2017		2016		Change			% Change
	(dollars in millions)									(dollars in millions)
Retail revenues	$	33.1	$	36.9	$	(3.8	)	(10.3	)%	$	38.2	$	33.1	$	5.1		15.4	%
Regulatory amortization	2.4		2.4		—			—		2.0		2.4		(0.4		)	(16.7	)
Total retail revenues	35.5		39.3		(3.8		)	(9.7	)	40.2		35.5		4.7			13.2
Wholesale and other	9.2		9.9		(0.7		)	(7.1	)	9.8		9.2		0.6			6.5
Total Revenues	44.7		49.2		(4.5		)	(9.1	)	50.0		44.7		5.3			11.9
Total Cost of Sales	9.5		13.6		(4.1		)	(30.1	)	13.9		9.5		4.4			46.3
Gross Margin	$	35.2	$	35.6	$	(0.4	)	(1.1	)%	$	36.1	$	35.2	$	0.9		2.6	%


	Revenues				Dekatherms (Dkt)		Customer Counts		Revenues				Dekatherms (Dkt)		Customer Counts
	2016		2015		2016	2015	2016	2015	2017		2016		2017	2016	2017	2016
	(in thousands)								(in thousands)
Montana	$	14,228	$	15,666	1,765	1,826	168,006	165,954	$	16,507	$	14,228	1,981	1,765	170,311	168,006
South Dakota	3,980		4,423		487	472	39,088	38,697	4,297		3,980		512	487	39,436	39,088
Nebraska	3,425		3,643		420	384	37,034	36,800	4,104		3,425		436	420	37,192	37,034
Residential	21,633		23,732		2,672	2,682	244,128	241,451	24,908		21,633		2,929	2,672	246,939	244,128
Montana	7,097		8,026		922	976	23,238	22,989	8,211		7,097		1,034	922	23,548	23,238
South Dakota	2,343		2,886		516	493	6,421	6,262	2,750		2,343		521	516	6,536	6,421
Nebraska	1,673		1,880		336	310	4,707	4,627	2,057		1,673		342	336	4,765	4,707
Commercial	11,113		12,792		1,774	1,779	34,366	33,878	13,018		11,113		1,897	1,774	34,849	34,366
Industrial	153		159		22	21	259	263	156		153		21	22	252	259
Other	190		169		30	24	158	152	165		190		24	30	158	158
Total Retail Gas	$	33,089	$	36,852	4,498	4,506	278,911	275,744	$	38,247	$	33,089	4,871	4,498	282,198	278,911


	Heating Degree Days			2016 as compared with:		Heating Degree Days			2017 as compared with:
	2016	2015	Historic Average	2015	Historic Average	2017	2016	Historic Average	2016	Historic Average
Montana	1,011	1,097	1,282	8% warmer	21% warmer	1,133	1,011	1,265	12% colder	10% warmer
South Dakota	1,246	1,180	1,474	6% colder	15% warmer	1,321	1,246	1,410	6% colder	6% warmer
Nebraska	1,038	981	1,206	6% colder	14% warmer	1,028	1,038	1,154	1% warmer	11% warmer

The following summarizes the components of the changes in natural gas gross margin for the three months ended June 30, ~~2016~~2017 and ~~2015~~2016:

Gross Margin 2016 vs. 2015
(in millions)
Gross Margin Items Impacting Net Income
Retail volumes $ (1.3 )
Natural gas production 0.9
Lost revenue adjustment mechanism 0.8
Other (0.5 )
Change in Gross Margin Impacting Net Income (0.1 )

Gross Margin Item Offset in Operating Expenses
Gas production gathering fees (0.6 )
Property taxes recovered in trackers 0.3
Change in Item Offset Within Net Income (0.3 )
Decrease in Consolidated Gross Margin $ (0.4 )



	Gross Margin 2017 vs. 2016
	(in millions)
Gross Margin Items Impacting Net Income
Retail volumes	$	1.3
2016 Lost revenue adjustment mechanism	(0.8		)
Production	(0.1		)
Other	(0.2		)
Change in Gross Margin Impacting Net Income	0.2

Gross Margin Items Offset in Operating Expenses
Production gathering fees	0.4
Property taxes recovered in trackers	0.3
Change in Items Offset Within Net Income	0.7
Increase in Gross Margin	$	0.9

Gross margin for items impacting net income ~~decreased $0.1~~increased $0.2 million ~~including~~due to an increase in retail volumes in our Montana and South Dakota jurisdictions due to colder spring weather and customer growth, partly offset by the following:

~~A decrease~~The recognition in ~~natural gas volumes due primarily to warmer spring weather, partly offset by customer growth; offset by~~

~~An increase in natural gas production due to a change in interim rates based on actual costs; and~~

~~The recognition~~2016 of $0.8 million of deferred revenue as a result of a MPSC final order in our tracker ~~filings, which was~~filings; and

A decrease in production margin due primarily to a $0.4 million reduction in interim rates, partly offset by a $0.3 million increase in ~~part by the elimination of the lost revenue adjustment mechanism decreasing the recovery of our fixed costs;~~overhead fees.

The change in consolidated gross margin also includes the following items that had no impact on net income:

~~A decrease~~An increase in ~~natural gas~~production gathering fees ~~(offset~~is offset by ~~reduced~~an increase in operating ~~expenses);~~expenses; and

An increase in revenues for property taxes included in trackers ~~(offset~~is offset by increased property tax ~~expense).~~

~~Average natural gas supply prices decreased in 2016 resulting in lower retail revenues and cost of sales as compared with 2015,~~expense with no impact to ~~gross margin. In addition, our~~net income.

Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

Six Months Ended June 30, ~~2016~~2017 Compared with the Six Months Ended June 30, ~~2015~~2016


	Results											Results
	2016			2015			Change			% Change		2017			2016			Change			% Change
	(dollars in millions)											(dollars in millions)
Retail revenues	$	117.0		$	138.6		$	(21.6	)	(15.6	)%	$	137.1		$	117.0		$	20.1		17.2	%
Regulatory amortization	(0.6		)	(0.6		)	—			—		(6.6		)	(0.6		)	(6.0		)	1,000.0
Total retail revenues	116.4			138.0			(21.6		)	(15.7	)	130.5			116.4			14.1			12.1
Wholesale and other	19.5			21.2			(1.7		)	(8.0	)	20.6			19.5			1.1			5.6
Total Revenues	135.9			159.2			(23.3		)	(14.6	)	151.1			135.9			15.2			11.2
Total Cost of Sales	41.3			62.1			(20.8		)	(33.5	)	48.3			41.3			7.0			16.9
Gross Margin	$	94.6		$	97.1		$	(2.5	)	(2.6	)%	$	102.8		$	94.6		$	8.2		8.7	%


	Revenues				Dekatherms (Dkt)		Customer Counts		Revenues				Dekatherms (Dkt)		Customer Counts
	2016		2015		2016	2015	2016	2015	2017		2016		2017	2016	2017	2016
	(in thousands)								(in thousands)
Montana	$	50,553	$	55,497	6,722	6,588	167,895	165,785	$	60,275	$	50,553	7,903	6,722	170,238	167,895
South Dakota	14,128		18,174		1,874	2,038	39,219	38,893	15,101		14,128		2,027	1,874	39,563	39,219
Nebraska	11,244		15,079		1,558	1,703	37,172	37,011	13,134		11,244		1,684	1,558	37,332	37,172
Residential	75,925		88,750		10,154	10,329	244,286	241,689	88,510		75,925		11,614	10,154	247,133	244,286
Montana	24,982		27,921		3,446	3,424	23,231	22,981	30,144		24,982		4,125	3,446	23,550	23,231
South Dakota	8,952		12,132		1,771	1,868	6,442	6,289	10,179		8,952		1,856	1,771	6,558	6,442
Nebraska	5,946		8,538		1,136	1,240	4,727	4,660	6,969		5,946		1,216	1,136	4,793	4,727
Commercial	39,880		48,591		6,353	6,532	34,400	33,930	47,292		39,880		7,197	6,353	34,901	34,400
Industrial	590		725		85	92	261	263	662		590		93	85	254	261
Other	576		555		92	80	158	152	612		576		95	92	158	158
Total Retail Gas	$	116,971	$	138,621	16,684	17,033	279,105	276,034	$	137,076	$	116,971	18,999	16,684	282,446	279,105


	Heating Degree Days			2016 as compared with:		Heating Degree Days			2017 as compared with:
	2016	2015	Historic Average	2015	Historic Average	2017	2016	Historic Average	2016	Historic Average
Montana	3,998	3,988	4,570	-	13% warmer	4,601	3,998	4,509	15% colder	2% colder
South Dakota	4,920	5,269	5,548	7% warmer	11% warmer	5,211	4,920	5,535	6% colder	6% warmer
Nebraska	3,989	4,355	4,587	8% warmer	13% warmer	4,110	3,989	4,578	3% colder	10% warmer

The following summarizes the components of the changes in natural gas gross margin for the six months ended June 30, ~~2016~~2017 and ~~2015~~2016:

Gross Margin 2016 vs. 2015
(in millions)
Gross Margin Items Impacting Net Income
Retail volumes $ (1.1 )
Natural gas production (0.7 )
Lost revenue adjustment mechanism 0.6
Other (0.9 )
Change in Gross Margin Impacting Net Income (2.1 )

Gross Margin Item Offset in Operating Expenses
Gas production gathering fees (1.0 )
Property taxes recovered in trackers
0.6
Change in Item Offset Within Net Income (0.4 )
Decrease in Consolidated Gross Margin $ (2.5 )



	Gross Margin 2017 vs. 2016
	(in millions)
Gross Margin Items Impacting Net Income
Retail volumes	$	7.3
2016 Lost revenue adjustment mechanism	(0.8		)
Production	(0.7		)
Other	0.5
Change in Gross Margin Impacting Net Income	6.3

Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers	1.5
Production gathering fees	0.4
Change in Items Offset Within Net Income	1.9
Increase in Gross Margin	$	8.2

~~This~~Gross margin for items impacting net income increased $6.3 million from an increase in retail volumes due to colder winter and spring weather and customer growth, partly offset by the following items:

The recognition in 2016 of $0.8 million of deferred revenue as a result of a MPSC final order in our tracker filings; and

A decrease in production margin due primarily to a $1.0 million reduction in interim rates, partly offset by a $0.3 million increase in overhead fees.

The change in consolidated gross margin ~~was primarily due to~~also includes the ~~same reasons discussed~~following items that had no impact on net income:

An increase in ~~the three months ended section above. In addition, average natural gas supply prices decreased~~revenues for property taxes included in ~~2016 resulting in lower retail revenues and cost of sales as compared with 2015,~~trackers is offset by increased property tax expense with no impact to ~~gross margin.~~ net income; and

An increase in production gathering fees is offset by an increase in operating expenses.

Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.



LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Funds

We require liquidity to support and grow our business, and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, and to repay debt. We believe our cash flows from operations and existing borrowing capacity should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures (excluding strategic growth opportunities). The amount of capital expenditures and dividends are subject to certain factors including the use of existing cash, cash equivalents and the receipt of cash from operations. In addition, a material change in operations or available financing could impact our current liquidity and ability to fund capital resource requirements, and we may defer a portion of our planned capital expenditures as necessary.

We issue debt securities to refinance retiring maturities, reduce short-term debt, fund construction programs and for other general corporate purposes. To fund our strategic growth opportunities we utilize available cash flow, debt capacity and equity issuances that allow us to maintain investment grade ratings. We ~~expect to issue incremental debt securities during the second half of 2016 to fund capital investment and maintain liquidity, consistent with our~~ plan to maintain a 50 - 55 percent debt to total capital ratio excluding capital ~~leases. In addition, we~~leases, and expect to continue ~~targeting~~to target a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets.

Short-term liquidity is provided by internal cash flows, the sale of commercial paper and use of our revolving credit facility. We utilize our short-term borrowings ~~and/~~and / or revolver availability to manage our cash flows due to the seasonality of our business, and utilize any cash on hand in excess of current operating requirements to invest in our business and reduce borrowings. Short-term borrowings may also be used to temporarily fund utility capital requirements. As of June 30, ~~2016~~2017, our total net liquidity was approximately ~~$102.2~~$113.2 million,, including ~~$9.0~~$16.9 million of cash and ~~$93.2~~$96.3 million of revolving credit facility availability. Revolving credit facility availability was ~~$97.2~~$119.3 millionas of July ~~15, 2016~~21, 2017.~~. During the second quarter of 2016, we issued $60 million of South Dakota First Mortgage Bonds. Proceeds were used to redeem $55 million of First Mortgage Bonds due in 2018.~~

The following table presents additional information about short term borrowings during the ~~three~~six months ended June 30, ~~2016~~2017 (in millions):


Amount outstanding at period end	$	256.8	$	303.7
Daily average amount outstanding	$	175.3	$	223.2
Maximum amount outstanding	$	256.8	$	303.7

Factors Impacting our Liquidity

Supply Costs - Our operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from natural gas and electric sales typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows and utilization of our existing revolver, are used to purchase natural gas to place in storage, perform maintenance and make capital improvements.

The effect of this seasonality on our liquidity is also impacted by changes in the market prices of our electric and natural gas supply, which is currently recovered through various monthly cost tracking mechanisms. These energy supply tracking mechanisms are designed to provide stable and timely recovery of supply costs on a monthly basis during the July to June annual tracking period, with an adjustment in the following annual tracking period to correct for any under or over collection in our monthly trackers. Due to the lag between our purchases of electric and natural gas commodities and revenue receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above; therefore we usually under collect in the fall and winter and over collect in the spring. Fluctuations in recoveries under our cost tracking mechanisms can have a significant effect on cash flows from operations and make year-to-year comparisons difficult. Montana law defining our current electric tracking mechanism was repealed effective July 1, 2017, and the MPSC has outlined a process for implementing a replacement mechanism. We expect a new mechanism to be established, but cannot predict how this may impact the timing of recovery of cash flows associated with our Montana electric supply costs.

As of June 30, ~~2016~~2017, we are under collected on our supply trackers by approximately ~~$9.6~~$6.5 million,, as compared with an under collection of ~~$29.4~~$11.7 million as of December 31, ~~2015,~~2016, and ~~$9.2~~$9.6 million as of June 30, ~~2015~~2016.

Credit Ratings

In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, and impact our trade credit availability. Fitch Ratings (Fitch), ~~Moody’s Investors Service (Moody's)~~Moody's and Standard and Poor’s Ratings Service (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of July ~~15, 2016,~~21, 2017, our current ratings with these agencies are as follows:



	Senior Secured Rating	Senior Unsecured Rating	Commercial Paper	Outlook
Fitch	A	A-	F2	Stable
Moody’s (1)	A1A2	A3Baa1	Prime-2	Negative
S&P	A-	BBB	A-2	Stable

_____________________

(1) In March 2017, Moody's downgraded our senior secured rating to A2, from A1, and our unsecured credit rating to Baa1, from A3, while maintaining a negative outlook. Moody's cited weak financial metrics and a heightened degree of regulatory uncertainty in Montana as reasons for the downgrade. Moody's maintained a negative outlook, citing a more contentious regulatory relationship in Montana, our primary regulatory jurisdiction, resulting in unpredictable regulatory outcomes.

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Cash Flows

The following table summarizes our consolidated cash flows (in millions):


	Six Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2017			2016
Operating Activities
Net income	$	73.6		$	82.4		$	78.4		$	75.4
Non-cash adjustments to net income	90.1			90.3			92.8			88.3
Changes in working capital	(26.8		)	7.5			9.6			(26.8		)
Other noncurrent assets and liabilities	4.1			10.2			(3.0		)	4.1
Cash Provided by Operating Activities	141.0			190.4			177.8			141.0

Investing Activities
Property, plant and equipment additions	(121.2		)	(131.2		)	(119.1		)	(121.2		)
Change in restricted cash	—			9.2
Acquisitions	—			(0.5		)
Other	0.1			0.1			0.4			0.1
Cash Used in Investing Activities	(121.1		)	(122.4		)	(118.7		)	(121.1		)

Financing Activities
Issuances of long-term debt, net	5.0			50.0			—			5.0
Issuances (repayments) of short-term borrowings, net	26.9			(47.9		)
Issuances of short-term borrowings, net							2.8			26.9
Dividends on common stock	(47.9		)	(44.8		)	(50.4		)	(47.9		)
Financing costs	(5.3		)	(11.7		)	(0.1		)	(5.3		)
Other	(1.6		)	(1.1		)	0.4			(1.6		)
Cash Used in Financing Activities	(22.9		)	(55.5		)	(47.3		)	(22.9		)

(Decrease) increase in Cash and Cash Equivalents	$	(3.0	)	$	12.5
Increase (Decrease) in Cash and Cash Equivalents							$	11.8		$	(3.0	)
Cash and Cash Equivalents, beginning of period	$	12.0		$	20.4		$	5.1		$	12.0
Cash and Cash Equivalents, end of period	$	9.0		$	32.9		$	16.9		$	9.0

Cash Provided by Operating Activities

As of June 30, ~~2016~~2017, cash and cash equivalents were $~~9.0~~16.9 million as compared with ~~$12.0~~$5.1 million at December 31, ~~2015~~2016 and $~~32.9~~9.0 million at June 30, ~~2015~~2016. Cash provided by operating activities totaled $~~141.0~~177.8 million for the six months ended June 30, ~~2016~~2017 as compared with $~~190.4~~141.0 million during the six months ended June 30, ~~2015.~~2016. This ~~decrease~~increase in operating cash flows is primarily due to lower 2016 cash flows due to customer refunds associated with the DGGS FERC ruling and interim rates in our South Dakota electric rate case of approximately $30.8 million ~~($27.3~~and $7.2 million, ~~of deferred revenues plus accrued interest of $3.5 million) to customers during the first six months of 2016, and lower net income.~~respectively.

Cash Used in Investing Activities

Cash used in investing activities decreased by approximately ~~$1.3~~$2.4 million as compared with the first six months of ~~2015.~~2016. Plant additions during ~~2016~~2017 include maintenance additions of approximately $~~63.4~~58.9 million, capacity related capital expenditures of approximately $43.7 million, and infrastructure capital expenditures of approximately $16.5 million. Plant additions during the first six months of 2016 included maintenance additions of approximately $63.4 million, capacity related capital expenditures of approximately $34.4 million, and infrastructure capital expenditures of approximately ~~$23.4 million~~. Plant additions during the first six months of 2015 included maintenance additions of approximately $85.8 million, supply related capital expenditures of approximately $19.8 million, which were primarily related to electric generation facilities in South Dakota, and infrastructure capital expenditures of approximately $25.6$23.4 million.

Cash Used in Financing Activities

Cash used in financing activities totaled $~~22.9~~47.3 million during the six months ended June 30, ~~2016~~2017 as compared with ~~$55.5~~$22.9 million during the six months ended June 30, ~~2015.~~2016. During the six months ended June 30, 2017, net cash used in financing activities reflects payment of dividends of $50.4 million, partially offset by net issuances of commercial paper of $2.8 million. During the six months ended June 30, 2016, net cash used in financing activities ~~includes the payment~~included payments of dividends of $47.9 million and the payment of financing costs of $5.3 million, partially offset

by net issuances of commercial paper of $26.9 million and net proceeds from the issuance of debt of $5.0 million. During the six months ended June 30, 2015, net cash used in financing activities consisted of net repayments of commercial paper of $47.9 million, the payment of dividends of $44.8 million, and the payment of financing costs of $11.7 million, offset in part by net proceeds from the issuance of debt of $50.0 million.

~~Debt Issuance -~~ In June 2016, we issued $60 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.80% maturing in 2026. These bonds are secured by our electric and natural gas assets in South Dakota and were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended. Proceeds were used to redeem our 6.05%, $55 million South Dakota First Mortgage Bonds due 2018.

Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of June 30, ~~2016~~2017. See our Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016 for additional discussion.


	Total		2016		2017		2018		2019		2020		Thereafter		Total		2017		2018		2019		2020		2021		Thereafter
	(in thousands)														(in thousands)
Long-term debt	$	1,773,714	$	—	$	—	$	—	$	250,000	$	—	$	1,523,714	$	1,793,797	$	—	$	—	$	250,000	$	—	$	—	$	1,543,797
Capital leases	27,278		953		1,979		2,133		2,298		2,476		17,439		25,373		1,027		2,133		2,298		2,476		2,668		14,771
Short-term borrowings	256,806		256,806		—		—		—		—		—		303,658		303,658		—		—		—		—		—
Estimated pension and other postretirement obligations (1)	66,180		12,011		13,661		13,554		13,489		13,465		N/A		65,585		11,956		13,684		13,577		13,274		13,094		N/A
Qualifying facilities liability (2)	918,813		36,785		74,607		76,703		78,836		80,984		570,898		844,725		37,304		76,703		78,836		80,984		82,941		487,957
Supply and capacity contracts (3)	1,793,018		121,510		197,966		151,017		147,236		112,364		1,062,925		1,928,020		107,793		159,430		158,478		126,468		110,532		1,265,319
Contractual interest payments on debt (4)	1,422,676		42,224		83,825		83,635		73,620		65,695		1,073,677		1,330,494		40,771		81,541		73,616		65,691		65,393		1,003,482
Environmental remediation obligations (1)	6,740		1,140		1,650		1,650		1,500		800		N/A		5,900		700		1,650		2,150		800		600		N/A
Total Commitments (5)	$	6,265,225	$	471,429	$	373,688	$	328,692	$	566,979	$	275,784	$	4,248,653	$	6,297,552	$	503,209	$	335,141	$	578,955	$	289,693	$	275,228	$	4,315,326

_________________________


(1)	We estimate cash obligations related to our pension and other postretirement benefit programs and environmental remediation obligations for five years, as it is not practicable to estimate thereafter. Pension and postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.


(2)	Certain QFs require us to purchase minimum amounts of energy at prices ranging from $74 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $~~0.9 billion~~844.7 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately ~~$0.7 billion~~.$654.5 million.


(3)	We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 2627 years.


(4)	For our variable rate short-term borrowings outstanding, we have assumed an average interest rate of ~~0.89%~~1.30% through maturity.


(5)	Potential tax payments related to uncertain tax positions are not practicable to estimate and have been excluded from this table.



CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management’s discussion and analysis of financial condition and results of operations is based on our Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances.

As of June 30, ~~2016~~2017, there have been no significant changes with regard to the critical accounting policies disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016. The policies disclosed included the accounting for the following: goodwill and long-lived assets, ~~qualifying facilities~~QF liability, revenue recognition, regulatory assets and liabilities, pension and postretirement benefit plans, and income taxes. We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and credit exposure. Management has established comprehensive risk management policies and procedures to manage these market risks.

Interest Rate Risk

Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. We manage our interest rate risk by issuing primarily fixed-rate long-term debt with varying maturities, refinancing certain debt and, at times, hedging the interest rate on anticipated borrowings. All of our debt has fixed interest rates, with the exception of our revolving credit facility. The revolving credit facility bears interest at the lower of prime or available rates tied to the Eurodollar rate plus a credit spread, ranging from 0.88% to 1.75%. To more cost effectively meet short-term cash requirements, we issue commercial paper supported by our revolving credit facility. Since commercial paper terms are short-term, we are subject to interest rate risk. As of June 30, ~~2016~~2017, we had approximately $~~256.8~~303.7 million of commercial paper outstanding and no borrowings on our revolving credit facility. A 1% increase in interest rates would increase our annual interest expense by approximately ~~$2.6~~$3.0 million.

Commodity Price Risk

We are exposed to commodity price risk due to our reliance on market purchases to fulfill a portion of our electric and natural gas supply requirements. We also participate in the wholesale electric market to balance our supply of power from our own generating resources. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

As part of our overall strategy for fulfilling our electric and natural gas supply requirements, we employ the use of market purchases and sales, including forward contracts. These types of contracts are included in our supply portfolios and in some instances, are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. These contracts are part of an overall portfolio approach intended to provide price stability for consumers. As a regulated utility, our exposure to market risk caused by changes in commodity prices is substantially mitigated because these commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by applicable state regulatory commissions.

Counterparty Credit Risk

We are exposed to counterparty credit risk related to the ability of these counterparties to meet their contractual payment obligations, and the potential non-performance of counterparties to deliver contracted commodities or services at the contracted price. If counterparties seek financial protection under bankruptcy laws, we are exposed to greater financial risks. We are also exposed to counterparty credit risk related to providing transmission service to our customers under our Open Access Transmission Tariff and under gas transportation agreements. We have risk management policies in place to limit our transactions to high quality counterparties. We monitor closely the status of our counterparties and take action, as appropriate, to further manage this risk. This includes, but is not limited to, requiring letters of credit or prepayment terms. There can be no assurance, however, that the management tools we employ will eliminate the risk of loss.


ITEM 4.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and accumulated and communicated to management, including the principal executive officer and principal financial officer to allow timely decisions regarding required disclosure.

We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

See Note ~~13,~~12, Commitments and Contingencies, to the Financial Statements for information regarding legal proceedings.

ITEM 1A. RISK FACTORS -

You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our common stock or other securities.

We are subject to potential unfavorable state and federal regulatory outcomes. To the extent our incurred costs are deemed imprudent by the applicable regulatory commissions or certain regulatory mechanisms are not available, we may not recover some of our costs, which could adversely impact our results of operations and liquidity.

Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. We provide service at rates established by several regulatory commissions. These rates are generally set based on an analysis of our costs incurred in a historical test year. In addition, each regulatory commission sets rates based in part upon their acceptance of an allocated share of total utility costs. When commissions adopt different methods to calculate inter-jurisdictional cost allocations, some costs may not be recovered. Thus, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs.

In addition to ~~general~~ rate cases, our cost tracking mechanisms are a significant component of how we recover our costs. ~~Our~~Historically, our wholesale costs for electricity and natural gas supply are recovered through various pass-through cost tracking mechanisms in each of the states we serve. In April 2017, the Montana legislature passed HB 193, repealing the statute that provided for mandatory recovery of our prudently incurred electric supply costs effective July 1, 2017. In May and July 2017, the MPSC issued NCAs regarding the process to develop a replacement electric tracker mechanism. On July 14, 2017, we filed a proposed electric PCCAM with the MPSC. We believe the PCCAM filing is consistent with the MPSC's advocacy for HB 193, the MPSC's NCAs and the MDU adjustment mechanism that allows for recovery of 90 percent of the increases or decreases in fuel and purchased energy costs from an established baseline.

The ~~rates are~~MPSC has also raised questions regarding our earnings as compared to our authorized rate of return for 2016 for electric supply in the HB 193 related docket. In our 2016 annual report to the MPSC we indicated we earned less than our authorized rate of return with electric delivery service and supply combined. In April 2017, we submitted a filing to the MPSC indicating we will file a general electric rate case in 2018 based on a 2017 test year. The NCA established ~~based upon projected market prices or contractual obligations. As these variables change, we adjust our rates through our monthly trackers, which are subject~~a timeline for the parties to ~~approval by~~provide comments in July 2017, on the ~~applicable regulatory commissions.~~issue of whether the MPSC should require a September 2017 filing. We cannot guarantee how the MPSC may apply the statute in establishing a revised mechanism. To the extent our energy supply costs are deemed imprudent by the applicable state regulatory commissions, ~~we do not recover some~~or the passage of HB 193 reduces our ~~costs, which~~recovery or the timeliness of cash flows, the revised mechanism could adversely impact our results of ~~operations.~~operations and cash flows.

WeIn addition to the proposed changes to our electric tracking mechanism, we have received several unfavorable regulatory rulings in Montana, including:

•In 2016, the MPSC disallowed approximately $8.2 million of replacement power costs from ana 2013 outage at Colstrip Unit 4, and approximately $1.3 million of costs related to generation portfolio modeling previously recovered through our electric tracker filings.

•In October 2015, the MPSC issued an order eliminating the lost revenue adjustment mechanism. This mechanism was established in 2005 by the MPSC as a component of an approved energy efficiency program, by which we recovered on an after-the-fact basis a portion of our fixed costs that would otherwise have been collected in the kWh sales lost due to energy efficiency programs through our supply tracker. Lost revenues were removed prospectively effective December 1, 2015.

•In October 2013, the MPSC concluded that $1.4 million of incremental costs associated with regulation service acquired from third parties during a 2012 outage at DGGS were imprudently incurred, and disallowed recovery.

~~We appealed the October 2013 decision regarding DGGS outage costs to the Montana District Court, which, in August 2015, upheld the MPSC’s decision.~~

In ~~October 2015, we appealed the District Court’s decision to the Montana Supreme Court. We expect the matter to be fully briefed by the end of July 2016. Also, in~~ June 2016, we filed an appeal of the MPSC decision ~~in our 2014/2015 electric tracker filing~~ regarding the disallowance of portfolio modeling costs in Montana District Court. Also, in September 2016, we appealed the MPSC’s decisions regarding the disallowance of Colstrip Unit 4 replacement power costs and the modeling/planning costs in Montana District Court, arguing that these decisions were arbitrary and capricious, and violated Montana law.

In addition to our supply trackers, we file an annual property tax tracker with the MPSC for an automatic rate adjustment of our Montana property taxes, which allows recovery of 60 percent of the change in ~~property taxes.~~state and local taxes and fees. Adjusted rates are typically effective January 1st of each year. The MPSC ~~has~~ identified concerns with the amount of annual increases proposed by the Montana Department of Revenue. In June 2017, the MPSC adopted new rules to establish minimum filing requirements for property tax trackers. Some of the proposed rules appear to be based on a narrow interpretation of the enabling statute and suggest that the MPSC will challenge the amount and allocation of these taxes to customers. Under the new rules, we may face obstacles to the same recovery that we now achieve. Any change in recovery of property taxes could have a material impact on our results of operations.

In addition, the MPSC Order approving the purchase of hydro assets in Montana provided that customers would have no financial risk related to our temporary ownership of the Kerr facility, with a compliance filing required upon completion of the transfer to the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT). We sold any excess system generation, which was primarily due to our temporary ownership of Kerr, in the market and provided revenue credits to our Montana retail customers until the transfer to the CSKT. The cost of our temporary ownership was not included in rate base, and the benefits were provided to customers. In December 2015, we submitted the required hydro compliance filing to remove Kerr from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In January 2016, the MPSC approved an interim adjustment to our hydro generation rate based on the compliance filing, and opened a separate contested docket requesting additional detail on the adjustment to rates due to the conveyance of Kerr. A procedural schedule has been established and a hearing is scheduled for September 2016.

~~In addition,~~Additionally, in our regulatory filings related to DGGS, we proposed an allocation of approximately 80% of costs to retail customers subject to the MPSC's jurisdiction and approximately 20% allocated to wholesale customers subject to FERC's jurisdiction. In March 2012, the MPSC's final order approved using our proposed cost allocation methodology, but requires us to complete a study of the relative contribution of retail and wholesale customers to regulation capacity needs. The results of this study may be used in determining future cost allocations between retail and wholesale customers. However, there is no assurance that both the MPSC and FERC will agree on the results of this study, which could result in an inability to fully recover our ~~costs.~~

~~In May 2016, we received an order from the FERC denying~~costs in a May 2014 request for rehearing and requiring us to make refunds. The request for rehearing challenged a September 2012 FERC Administrative Law Judge's (ALJ) initial decision regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded that only a portion of these costs should be allocated to FERC jurisdictional customers. We had deferred cumulative revenue of approximately $27.3 million, consistent with the ALJ's initial decision, which was refunded to wholesale and choice customers in June 2016 in accordance with the FERC order. In June 2016, we filed a petition for review with the U.S. Circuit Court of Appeals for the District of Columbia Circuit. The briefing schedule for this appeal has not been established. The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. We are evaluating options to use DGGS in combination with other generation resources, including our hydro facilities, to minimize portfolio costs, which may facilitate cost recovery. The cost recovery of any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. If we are not able to obtain cost recovery of DGGS we may be required to record an impairment charge, which could have a material adverse effect on our operating results.

During the second quarter of 2015, we reached a settlement agreement with an insurance carrier for the former Montana Power Company for what were primarily generation related environmental remediation costs. As a result of this settlement, we recognized a net recovery of approximately $20.8 million, which is reflected as a reduction to operating expenses in our other segment. The environmental remediation costs were never reflected in customer rates and the litigation expenses have not been treated as utility expenses. In a 2002 order approving NorthWestern’s acquisition of the transmission and distribution assets of the Montana Power Company, the MPSC approved a stipulation in which NorthWestern agreed to release its customers from all environmental liabilities associated with the Montana Power Company’s generation assets. While we believe the recovery we recognized as a reduction to operating expenses is not subject to refund to customers, the MPSC could disagree with us and could ultimately require us to refund all or a portion of the net recovery to customers, which could have a material adverse effect on our operating results.future electric general rate filing.

Our ability to invest in additional generation is impacted by regulatory and public policy. Under ~~the Public Utility Regulatory Policies Act of 1978,~~PURPA, electric utilities are required, with exceptions, to purchase energy and capacity from independent power producers that are ~~qualifying co-generation facilities and qualifying small power production facilities (QFs).~~QFs. Our requirements to procure power from these sources could impact our ability to make generation investments depending upon the number and size of QF contracts we ultimately enter into. ~~In addition, the~~The cost to procure power from these QFs may not be a cost effective resource for customers, or the type of generation resource needed, resulting in increased supply costs.

In June 2017, the MPSC held a work session to discuss our application for approval of a revised tariff for standard rates for small QFs. In July 2017, the MPSC issued an order establishing a maximum 10-year contract length with a rate adjustment after the first five years, and approving rates that do not include costs associated with the risk of future carbon dioxide emissions regulations. In this same order, the MPSC indicated they will apply the 10-year contract term to us for future electric supply resource transactions. We are ~~subject~~evaluating the impact of this decision and have suspended our competitive solicitation process to ~~many FERC rules~~determine the lowest-cost / least-risk approach for addressing our intermittent capacity and ~~orders that regulate~~reserve margin needs in Montana. This order may have a significant impact on our ~~electric and natural gas business and are subject~~approach to ~~periodic audits. In March 2015, FERC began conducting an audit of~~meet our ~~open access transmission tariffs and operations in Montana and South Dakota. These audits typically take up to 24 months to complete.~~portfolio needs.

We must also comply with established reliability standards and requirements, which apply to the North American Electric Reliability Corporation (NERC) functions in both the Midwest Reliability Organization for our South Dakota operations and Western ~~Electric~~Electricity Coordination Council for our Montana operations. The FERC, NERC, or a regional reliability organization may assess penalties against any responsible entity that violates their rules, regulations or standards. Violations may be discovered through various means, including self-certification, self-reporting, compliance investigations, audits, periodic data

submissions, exception reporting, and complaints. Penalties for the most severe violations can reach as high as $1approximately $1.2 million per violation, per day. If a serious reliability incident or other incidence of noncompliance did occur, it could have a material adverse effect on our operating and financial results.

We are also subject to changing federal and state laws and regulations. Congress and state legislatures may enact legislation that adversely affects our operations and financial results.

We are subject to existing, and potential future, federal and state legislation. In the planning and management of our operations, we must address the effects of legislation within a regulatory framework. Federal and state laws can significantly impact our operations, whether it is new or revised statutes directly affecting the electric and gas industry, or other issues such as taxes.

We are subject to changing tax laws, regulations, and interpretations in multiple jurisdictions. Corporate tax reform continues to be a priority in the U.S. Changes to the U.S. tax system could have significant effects, positive and negative, on our effective tax rate, and on our deferred tax assets and liabilities. In addition, the timing of realization of certain tax benefits may be further delayed in the event of future extensions of bonus depreciation or expensing of capital investments and impact our ability to utilize our federal and state net operating loss carryforwards.

In addition, new or revised statutes can also materially affect our operations through impacting existing regulations or requiring new regulations. These changes are ongoing, and we cannot predict the future course of changes or the ultimate effect that this changing environment will have on us. Changes in laws, and the resulting regulations and tariffs and how they are implemented and interpreted, may have a material adverse effect on our ~~businesses,~~ financial condition, results of operations and cash flows.

~~In March~~On June 22, 2016, ~~the U.S. Senate passed~~then-President Obama signed the Securing America’s Future Energy: Protecting our Infrastructure of Pipelines and Enhancing Safety Act (SAFE PIPES Act), which would reauthorize appropriations for the Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA) safety programs through 2019. The ~~bill~~law prioritizes PHMSA's completion of outstanding regulations. In addition, ~~in March 2016,~~ PHMSA proposed ~~revisions~~regulations to safety standards for natural gas transmission and gathering pipelines. The long-anticipated proposal could impose significant regulatory requirements for additional miles of natural gas pipeline, including pipelines constructed prior to 1970 which were previously exempt from PHMSA regulations related to pressure testing. It would also create a new "Moderate Consequence Area" category to expand safety protocols to pipelines in moderately populated areas. The rule also would codify the Integrity Verification Process (IVP) which is a process that will require companies to have reliable, traceable, verifiable, and complete records for pipelines in certain areas. The rule would establish a deadline for IVP completion that we will be required to meet. Costs incurred to comply with the proposed regulations may be material.

We are subject to extensive and changing environmental laws and regulations and potential environmental liabilities, which could have a material adverse effect on our liquidity and results of operations.

We are subject to extensive laws and regulations imposed by federal, state, and local government authorities in the ordinary course of operations with regard to the environment, including environmental laws and regulations relating to air and water quality, protection of natural resources, migratory birds and other wildlife, solid waste disposal, coal ash and other environmental considerations. We believe that we are in compliance with environmental regulatory requirements; however, possible future developments, such as more stringent environmental laws and regulations, and the timing of future enforcement proceedings that may be taken by environmental authorities, could affect our costs and the manner in which we conduct our business and could require us to make substantial additional capital expenditures or abandon certain projects.

~~National and international actions have been initiated to address global climate change and the contribution of GHG emissions including, most significantly, carbon dioxide.~~ In ~~August~~October 2015, the EPA ~~released final~~published standards ~~of performance~~for states to ~~limit~~implement to control GHG emissions from ~~new, modified and reconstructed fossil fuel~~existing electric generating ~~units and from newly constructed and reconstructed natural gas combined cycle~~ units. ~~In a separate action that also affects power plants, in August 2015,~~These standards are referred to as the ~~EPA released its final rule establishing GHG performance standards for existing power plants under Clean Air Act Section 111(d) (the~~ Clean Power Plan ~~or CPP)~~(CPP).

The CPP reduction of 47.4 percent in carbon dioxide emissions in Montana by 2030 is the greatest reduction target among the lower 48 states, according to a nationwide analysis. Our Montana generation portfolio emits less carbon on average than the EPA's 2030 target due to investments we made prior to 2013 in carbon-free generation resources. However, the CPP's target reduction is applied on a statewide basis, and investments made prior to 2012 are not counted in the CPP's 2030 target. We, ~~asked the BBER to study the potential impacts of the CPP across Montana. The BBER study looked at the implications of closing the Colstrip generating facilities in southeast Montana as~~along with a scenario for complying with the federal rule. The study's conclusions describe the likely loss of jobs and population, the decline in the local and state tax base, the impact on businesses statewide, and the closure's impact on electric reliability and affordability. The electricity produced at Unit 4 represents approximately 25 percent of our customer needs. Closing Colstrip would lead to higher utility rates in order to replace the base-load generation that currently is provided by Colstrip. Closing Colstrip would also create significant issues with the transmission grid that serves Montana, and we would lose transmission revenues that are credited to lower electric customer bills.

We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are or may become subject to the CPP and the various regulations discussed above that have been issued or proposed. Each state is

required by the CPP to submit a satisfactory plan to EPA by September 2018. The state plans will determine whether we will have to meet rate-based or mass-based requirements and, if the state adopts a mass-based plan, the number of ~~vintages of allowances that will be allocated to our facilities. Until the plans are submitted, or a federal plan is imposed, we cannot predict the impact of the CPP on us.~~

On October 23, 2015, the same date the CPP was published in the Federal Register, we along with other utilities, trade groups, coal producers, labor and business organizations, filed Petitions for Review of the CPP with the United States Court of Appeals for the District of Columbia Circuit. Accompanying these Petitions for Review were Motions to Stay the implementation of the CPP. On January 21, 2016, the U.S. Court of Appeals for the District of Columbia denied the requests for stay but ordered expedited briefing on the merits. On January 26, 2016, 29 states and ~~state agencies asked~~other parties, filed lawsuits against the U.S. Supreme Court to issue an immediate stay of the CPP. On January 27, 2016, 60 utilities and allied petitioners also requested the U.S. Supreme Court to immediately stay the CPP, and we were among the utilities seeking a stay. OnEPA standards. In February 9, 2016, the U.S. Supreme Court entered an order staying the ~~CPP. The stay~~implementation of the CPP ~~will remain~~standards. In a separate proceeding, in ~~place until~~January 2017, the U.S. Supreme Court either denies a petition for certiorari following the U.S. Court of Appeals’ decision on the substantive challenges to the CPP, if one is submitted, or until the U.S. Supreme Court enters judgment following grant of a petition for certiorari. On May 16, 2016, the U.S. Court of Appeals for the District of Columbia entered an order declaring the challenge to the CPP would be reviewed en banc, rather than by a three judge panel, and delayed oral argument until September 2016. An initial ruling on the challenge is not expected until early 2017, and the U.S. Supreme Court decision on challenges to the CPP is not anticipated until mid-2017, and, more likely, early 2018.

~~On December 22, 2015 we also filed an~~EPA denied our administrative Petition for Reconsideration ~~with~~that had requested the EPA ~~requesting that it~~ reconsider the CPP on the grounds that the CO₂ reductions in the CPP were substantially greater in Montana than in the proposed rule. ~~We also requested EPA stay~~In response, we filed a Petition for Review in the U.S. Court of Appeals for the District of Columbia in March 2017. Additional information regarding the CPP, ~~while it considered our Petition for Reconsideration. At this time,~~ the ~~EPA has taken no action on~~proposed reductions in South Dakota and Montana, and the ~~Petition for Reconsideration or stay request.~~pending litigation is included in Note 12 - Commitments and Contingencies to the Condensed Consolidated Financial Statements.

Requirements to reduce GHG emissions could cause us to incur material costs of compliance and increase our costs of procuring electricity. Although there continues to be changes in legislation and regulations that affect GHG emissions from power plants, technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistentThere is uncertainty associated with the ~~implementation~~new EPA Administration and the timeframe for actions that may be taken with regard to the existing and pending GHG-related regulations. In addition, in March 2017, President Trump signed an Executive Order instructing all federal agencies to review all regulations and other policies that burden the development or use of domestically produced energy resources and suspend, revise or rescind those that pose an undue burden beyond that required to protect the public interest. The order specifically identifies CPP as requiring review pursuant to this standard. In light of the Executive Order, the future of the CPP regulations and associated guidance is uncertain. However, if the CPP survives the Executive Order, the legal challenges and is implemented as written, it could result in significant additional compliance costs that would affect our future results of operations and financial position if such ~~requirements. We cannot predict with any certainty~~costs are not recovered through regulated rates. Due to the pending litigation and the uncertainties in the state approaches, the ultimate timing and impact of ~~these risks~~the CPP on our ~~results of operations.~~

~~We are evaluating the implications of these rules and technology available to achieve~~operations cannot be determined with certainty at this time. Complying with the CO₂emission performance standards. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from the final rules that, in our view, disproportionately impact customers in our region, and to seek relief from the final compliance requirements. We cannot predict the ultimate outcome of these matters nor what our obligations might be under the state compliance plans with any degree of certainty until they are finalized; however, complying with the carbon emission standards, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of our jointly owned facilities or for individual owners to participate in their proportionate ownership of the coal-fired generating units. This could lead to significant impacts to customer rates for recovery of plant improvements and / or closure related costs and costs to procure replacement power. In addition, these changes could impact system reliability due to changes in generation sources.

Many of these environmental laws and regulations provide for substantial civil and criminal fines for noncompliance which, if imposed, could result in material costs or liabilities. In addition, there is a risk of environmental damages claims from private parties or government entities. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair, upgrade or expansion of our facilities to meet future requirements and obligations under environmental laws.

To the extent that costs exceed our estimated environmental liabilities, or we are not successful in recovering remediation costs or costs to comply with the proposed or any future changes in rules or regulations, our results of operations and financial position could be adversely affected.

Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions or response to price increases. We are also impacted by market conditions outside of our service territories related to demand for transmission capacity and wholesale electric pricing.

Our revenues, results of operations and financial condition are impacted by customer growth and usage, which can be impacted by a number of factors, including the voluntary reduction of consumption of electricity and natural gas by our

customers in response to increases in prices and demand-side management programs, economic conditions impacting decreases in their disposable income, and the use of distributed generation resources or other emerging technologies for electricity. Advances in distributed generation technologies that produce power, including fuel cells, micro-turbines, wind turbines and solar cells, may reduce the cost of alternative methods of producing power to a level competitive with central power station electric production. Customer-owned generation itself reduces the amount of electricity purchased from utilities and has the effect of increasing rates unless retail rates are designed to share the costs of the distribution grid across all customers that benefit from their use. Such developments could affect the price of energy, could affect energy deliveries as customer-owned generation becomes more cost-effective, could require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy.

Both decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation ~~puts~~put downward pressure on load growth. Our electricity supply resource procurement plan includes an expected load growth assumption of 0.8 percent annually, which reflects low customer and usage increases, offset in part by these efficiency measures. Reductions in usage, attributable to various factors could materially affect our results of operations, financial position, and cash flows through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.

Demand for our Montana transmission capacity fluctuates with regional demand, fuel prices and weather related conditions. The levels of wholesale sales depend on the wholesale market price, market participants, transmission availability and the availability of generation, among other factors. Declines in wholesale market price, availability of generation, transmission constraints in the wholesale markets, or low wholesale demand could reduce wholesale sales. These events could adversely affect our results of operations, financial position and cash flows.

Weather and weather patterns, including normal seasonal and quarterly fluctuations of weather, as well as extreme weather events that might be associated with climate change, could adversely affect our results of operations and liquidity.

Our electric and natural gas utility business is seasonal, and weather patterns can have a material impact on our financial performance. Demand for electricity and natural gas is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenue and income when weather conditions are milder in the winter and cooler in the summer. In the event that we experience unusually mild winters or cool summers in the future, our results of operations and financial position could be adversely affected. Higher temperatures may also decrease the Montana snowpack, which may result in dry conditions and an increased threat of forest fires. Forest fires could threaten our communities and electric transmission lines and facilities. Any damage caused as a result of forest fires could negatively impact our financial condition, results of operations or cash flows. In addition, exceptionally hot summer weather or unusually cold winter weather could add significantly to working capital needs to fund higher than normal supply purchases to meet customer demand for electricity and natural gas. Our sensitivity to weather volatility is significant due to the absence of regulatory mechanisms, such as those authorizing revenue decoupling, lost margin recovery, and other innovative rate designs. There is also a concern that the physical risks of climate change could include changes in weather conditions, such as changes in the amount or type of precipitation and extreme weather events.

Climate change and the costs that may be associated with its impacts have the potential to affect our business in many ways, including increasing the cost incurred in providing electricity and natural gas, impacting the demand for and consumption of electricity and natural gas (due to change in both costs and weather patterns), and affecting the economic health of the regions in which we operate. Extreme weather conditions creating high energy demand on our own and/or other systems may raise market prices as we buy short-term energy to serve our own system. Severe weather impacts our service territories, primarily through thunderstorms, tornadoes and snow or ice storms. To the extent the frequency of extreme weather events increase, this could increase our cost of providing service. We derive a significant portion of our power supply from hydroelectric facilities. Because of our heavy reliance on hydroelectric generation, snowpack, the timing of run-off, drought conditions, and the availability of water can significantly affect operations. In addition, extreme weather may exacerbate the risks to physical infrastructure. We may not recover all costs related to mitigating these physical and financial risks.

Cyber and physical attacks, threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may affect our operations in unpredictable ways and could adversely affect our liquidity and results of operations.

We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber (such as hacking and viruses) and physical security breaches and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities are deemed critical infrastructure and provide the framework for our service infrastructure. These assets and the information technology systems on which they depend could be direct targets of, or indirectly affected by, cyber attacks and other disruptive activities, including cyber attacks and other disruptive activities on third party facilities that are interconnected to us through the regional transmission grid or natural gas pipeline infrastructure. Any significant interruption of these assets or systems could prevent us from fulfilling our critical business functions including delivering energy to our customers, and sensitive, confidential and other data could be compromised.

We rely on information technology networks and systems to operate our critical infrastructure, engage in asset management activities, and process, transmit and store electronic information including customer and employee information. Further, our infrastructure, networks and systems are interconnected to external networks and neighboring critical infrastructure systems. Security breaches could lead to system disruptions, generating facility shutdowns or unauthorized disclosure of confidential information. In particular, any data loss or information security lapses resulting in the compromise of personal information or the improper use or disclosure of sensitive or classified information could result in claims, remediation costs, regulatory sanctions, loss of current and future contracts, and serious harm to our reputation.

We are subject to laws and rules issued by multiple government agencies concerning safeguarding and maintaining the confidentiality of our security, customer and business information. One of the agencies, NERC, has issued comprehensive regulations and standards surrounding the security of our operating systems, and is continually in the process of developing updated and additional requirements with which the utility industry must comply. The increasing promulgation of NERC rules and standards will increase our compliance costs and our exposure to the potential risk of violations of standards.

Security threats continue to evolve and adapt. Cyber or physical attacks, terrorist acts, or disruptive activities could harm our business by limiting our ability to generate, purchase or transmit power and by delaying the development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure assets, and could adversely affect our operations by contributing to the disruption of supplies and markets for natural gas, oil and other fuels. These events could also impair our ability to raise capital by contributing to financial instability and reduced economic activity.

Our plans for future expansion through the acquisition of assets including natural gas reserves, capital improvements to current assets, generation investments, and transmission grid expansion involve substantial risks.

Acquisitions include a number of risks, including but not limited to, regulatory approval, additional costs, the assumption of material liabilities, the diversion of management’s attention from daily operations to the integration of the acquisition, difficulties in assimilation and retention of employees, and securing adequate capital to support the ~~transaction, and~~transaction. The regulatory ~~approval.~~process in which rates are determined may not result in rates that produce full recovery of our investments, or a reasonable rate of return. Uncertainties also exist in assessing the value, risks, profitability, and liabilities associated with certain businesses or assets and there is a possibility that anticipated operating and financial synergies expected to result from an acquisition do not develop. The failure to successfully integrate future acquisitions that we may choose to undertake could have an adverse effect on our financial condition and results of operations.

Our business strategy also includes significant investment in capital improvements and additions to modernize existing infrastructure, generation investments and transmission capacity expansion. The completion of generation and natural gas

investments and transmission projects are subject to many construction and development risks, including, but not limited to, risks related to permitting, financing, regulatory recovery, escalating costs of materials and labor, meeting construction budgets and schedules, and environmental compliance. In addition, these capital projects may require a significant amount of capital expenditures. We cannot provide certainty that adequate external financing will be available to support such projects. Additionally, borrowings incurred to finance construction may adversely impact our leverage, which could increase our cost of capital.

Our electric and natural gas operations involve numerous activities that may result in accidents and other operating risks and costs.

Inherent in our electric and natural gas operations are a variety of hazards and operating risks, such as fires, electric contacts, leaks, explosions and mechanical problems. These risks could cause a loss of human life, significant damage to property, loss of customer load, environmental pollution, impairment of our operations, and substantial financial losses to us and others. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. For our natural gas transmission and distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks potentially is greater.

Our owned and jointly owned electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

Operation of electric generating facilities involves risks, which can adversely affect energy output and efficiency levels. Operational risks include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error, catastrophic events such as fires, explosions, floods, and intentional acts of destruction or other similar occurrences affecting the electric generating facilities; and operational changes necessitated by environmental legislation, litigation or regulation. The loss of a major electric generating facility would require us to find other sources of supply or ancillary services, if available, and expose us to higher purchased power costs.

The six owners of Colstrip currently share the operating costs pursuant to the terms of an operating agreement among the owners of Units 3 and 4 and a common facilities agreement among the owners of all four units. As ~~discussed above,~~part of the ~~proposed consent decree relating to~~settlement of litigation brought by the Sierra Club and the Montana Environmental Information Center, against the owners and operator of Colstrip, ~~litigation call for~~the owners of Units 1 and 2 agreed to be shut down these units no later than July 2022. We do not have ownership in Units 1 and 2, and decisions regarding these units, including their shut down, were made by ~~2022. If~~their respective owners. When Units 1 and 2 discontinue operation, we anticipate incurring incremental operating costs with respect to our interest in Unit ~~4. In addition,~~4 and expect to experience a negative impact on our transmission revenue due to less energy available to transmit across our transmission lines. This reduction would be incorporated in ~~May 2016, Talen provided a two-year notice of its intent~~our next general electric rate filing, resulting in lower revenue credits to resign as the operator of Colstrip. We and the other owners are working to select a new operator, which we expect will increase operating costs. However, at this time we do not anticipate these increases will be material to our financial results.certain customers.

In early July 2013, following the return to service from a scheduled maintenance outage, Colstrip Unit 4 tripped off-line and incurred damage to its stator and rotor. Colstrip Unit 4 returned to service in early 2014. As discussed above, we were not able to fully recover our costs for the purchase of replacement power while Colstrip Unit 4 was out of service.

Colstrip Units 3 and 4 are supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through 2019. These contracts are necessary for the long-term operation of the facility. Negotiation of a new coal supply contract anticipates environmental reviews and permitting, and we cannot predict when or if those permits will be granted. If a new coal supply contract is not in place, we could continue under the current arrangement for several years if the mining company agrees, however the extraction costs would increase.

We also rely on a limited number of suppliers of coal for our electric generation, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity and operational issues and/or increased prices for coal transportation from a sole supplier.

We must meet certain credit quality standards. If we are unable to maintain investment grade credit ratings, our liquidity, access to capital and operations could be materially adversely affected.

A downgrade of our credit ratings to less than investment grade could adversely affect our liquidity. Certain of our credit agreements and other credit arrangements with counterparties require us to provide collateral in the form of letters of credit or cash to support our obligations if we fall below investment grade. Also, a downgrade below investment grade could hinder our ability to raise capital on favorable terms, including through the commercial paper markets. Higher interest rates on short-term borrowings with variable interest rates or on incremental commercial paper issuances could also have an adverse effect on our results of operations.

Poor investment performance of plan assets of our defined benefit pension and post-retirement benefit plans, in addition to other factors impacting these costs, could unfavorably impact our results of operations and liquidity.

Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors. Assumptions related to future costs, return on investments and interest rates have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance and changes in governmental regulations. Without sustained growth in the plan assets over time and depending upon interest rate changes as well as other factors noted above, the costs of such plans reflected in our results of operations and financial position and cash funding obligations may change significantly from projections.

Our obligation to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWH could expose us to material commodity price risk if certain QFs under contract with us do not perform during a time of high commodity prices, as we are required to make up the difference. In addition, we are subject to price escalation risk with one of our largest QF contracts.

As part of a stipulation in 2002 with the MPSC and other parties, we agreed to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWH through June 2029. The annual minimum energy requirement is achievable under normal QF operations, including normal periods of planned and forced outages. However, to the extent the supplied QF power for any year does not reach the minimum quantity set forth in the settlement, we are obligated to purchase the difference from other sources. The anticipated source for any QF shortfall is the wholesale market, which would subject us to commodity price risk if the cost of replacement power is higher than contracted QF rates.

In addition, we are subject to price escalation risk with one of our largest QF contracts due to variable contract terms. In estimating our QF liability, we have estimated an annual escalation rate of three percent over the remaining term of the contract (through June 2024). To the extent the annual escalation rate exceeds three percent, our results of operations, cash flows and financial position could be adversely affected.

~~We must meet certain credit quality standards. If we are unable to maintain investment grade credit ratings, our liquidity, access to capital and operations could be materially adversely affected.~~

ITEM 6. EXHIBITS -

(a) Exhibits

Exhibit 3.1— Amended and Restated Certificate of Incorporation of NorthWestern Corporation, dated May 3, 2016 (incorporated by reference to Exhibit 3.1 of NorthWestern Corporation's Current Report on Form 8-K, dated May 18, 2016, Commission File No. 1-10499).

Exhibit 3.2— Amended and Restated Bylaws of NorthWestern Corporation, dated May 12, 2016 (incorporated by reference to Exhibit 3.2 of NorthWestern Corporation's Current Report on Form 8-K, dated May 18, 2016, Commission File No. 1-10499).

Exhibit 4.1— Fourteenth Supplemental Indenture, dated as of June 1, 2016, between the NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 21, 2016, Commission File No. 1-10499).

~~Exhibit~~ 31.1—Certification of chief executive ~~officer.~~officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002.

Exhibit 31.2—Certification of chief financial ~~officer.~~officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002.

Exhibit 32.1—Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.2—Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 101.INS—XBRL Instance Document

Exhibit 101.SCH—XBRL Taxonomy Extension Schema Document

Exhibit 101.CAL—XBRL Taxonomy Extension Calculation Linkbase Document

Exhibit 101.DEF—XBRL Taxonomy Extension Definition Linkbase Document

Exhibit 101.LAB—XBRL Taxonomy Label Linkbase Document

Exhibit 101.PRE—XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



			NorthWestern Corporation
Date:	July ~~22, 2016~~26, 2017	By:	/s/ BRIAN B. BIRD
			Brian B. Bird
			Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer



EXHIBIT INDEX



Exhibit Number		Description
~~3.1~~		Amended and Restated Certificate of Incorporation of NorthWestern Corporation, dated May 3, 2016 (incorporated by reference to Exhibit 3.1 of NorthWestern Corporation's Current Report on Form 8-K, dated May 18, 2016, Commission File No. 1-10499).
~~3.2~~		Amended and Restated Bylaws of NorthWestern Corporation, dated May 12, 2016 (incorporated by reference to Exhibit 3.2 of NorthWestern Corporation's Current Report on Form 8-K, dated May 18, 2016, Commission File No. 1-10499).
~~4.1~~		Fourteenth Supplemental Indenture, dated as of June 1, 2016, between the NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 21, 2016, Commission File No. 1-10499).
*31.1		Certification of chief executive ~~officer.~~officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002.
*31.2		Certification of chief financial ~~officer.~~officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002.
*32.1		Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2		Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS		XBRL Instance Document
*101.SCH		XBRL Taxonomy Extension Schema Document
*101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF		XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB		XBRL Taxonomy Label Linkbase Document
*101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

_________________________


*	Filed herewith

6663



	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
Retail volumes	$	(1.3	)
Natural gas production	0.9
Lost revenue adjustment mechanism	0.8
Other	(0.5		)
Change in Gross Margin Impacting Net Income	(0.1		)

Gross Margin Item Offset in Operating Expenses
Gas production gathering fees	(0.6		)
Property taxes recovered in trackers	0.3
Change in Item Offset Within Net Income	(0.3		)
Decrease in Consolidated Gross Margin	$	(0.4	)

Location of amount reclassified from AOCL to Income

Amount Reclassified from AOCL into Income during the Six Months Ended June 30, 2017

Interest rate contracts

Interest Expense